announcement temporary handling

ANNOUNCEMENT

TEMPORARY HANDLING DUE TO

E-TENDER

_{WEB MAINTENANCE}

July 3

rd

_{, 2017}

Dear Sir/ Madam

We apologize for the unconveni

ence

situation due to many series of hacking activities to our official

web site which handle the Tender process of 1

st

_{Bid Round 2017 in the}

_{http://e-wkmigas.esdm.go.id.}

Regarding to the mentioned above, now we are trying our best effort to recover these website as soon

as possible. We also would like to inform you that all of tender process (registration, document access,

FAQ, etc) and communications is now tempora

r

y will be handle with our email addresses:

dmew.konvensional@esdm.go.id

for conventional area

and

dmen.konvensional@esdm.go.id

for unconventional area

Thank you for your cooperation and don

’

t hesitate to contact us.

Best Regards

Secretariat of Tender Committee

Please finds below our Booklet:

1. Conventional Oil & Gas Working Area- 1

st

_{Bidding Round 2017}

INDONESIA

Conventional Oil and Gas Bidding First Round

2017

THE GOVERNMENT OF

REPUBLIC OF INDONESIA

DIRECTORATE GENERAL OF OIL AND GAS

INDONESIA

Conventional Oil and Gas Bidding First Round

2017

DIRECTORATE GENERAL OF OIL AND GAS

Contractor (Including cost) (oil 43%)/(gas 48%) Government

(oil 57%)/(gas 52%)

Split does not include tax

1. Block status

2. Field location (onshore or ofshore, remote) 3. Reservoir depth

4. Supportting infrastructure 5. Reservoir condition 6. CO2 content

7. H2S content

8. Specific Gravity (API) 9. Local Content (TKDN) 10. Production phase

1 1. Oil prices

12. Cumulative production

10 Variable Components

2 Progressive Components

The Contractor obtains an "additional split" from the above split base, depends on actual conditions of :

The government will get additional taxes Gross Production

100%

Gross Split PSC

“Better State Part & Contractor Will Be More Eicient”

Regulation of MEMR Number 8/2017 :

“...it is deemed necessary to regulate the scheme and the basic provisions of the production sharing contract without the operating cost recovery mechanism.”

“The Gross Split Production Sharing Contract utilizes a base split production share mechanism, which may be adjusted, based on variable components and progressive components.”

Shifting from Cost Recovery PSC Model to Gross Split PSC eliminating “cost recovery“ issue in State Budgeting

simplifying business process (e.g work program approval, procurement) business risk mitigated by “incentives split”

eiciency of the operating cost

Cost Recovery PSC

Gross Production 100% Contractor (15%) Government (45%) Tax2 (6%) Contractor (9%) Government (51%) Contractor Take (49%) Cost Recovery1 (40%) Equity to be Split

(60%)

Gross

Nett

1_{in the last 2 years (averaged)} 2_{Tax of 40%}

INDONESIA

Conventional Oil and Gas Bidding First Round

2017 7.56 111.86 Aceh Central Sumatera South Sumatera

North Sumatera _Natuna

West Java East Java Kalimantan Sulawesi Maluku Papua 0.80 186.64 7.52 2,331.49 49.87 303.81 12.92 1,092.85 5.23 1,324.61 8.04 1,219.52 14.75 526.22 2.60 45.43 110.33 100.25 16.73 19.03 Oil (MMSTB) Gas (TSCF) Status January 2016

Indonesia Crude Oil and Gas Reserves

Oil Resources

Production: 831,000 BPD

: 3,306.91 MMSTB : 3,944.20 MMSTB : 7,251.11 MMSTB Proven

Potential Total

Gas Resources

Production: 7,940 MMSCFD

: 101.22 TSCF : 42.84 TSCF : 144.06 TSCF Proven

Potential Total

Working Area: 280 PSCs

: 195 PSCs : 71 PSCs : 14 PSCs Exploration

Production Development Souce : Ditjen Migas

0 5.000 10.000 15.000 20.000 25.000 30.000 35.000

2012

2013

2014

2015

2016

2D Seismic Survey

KM

0 2.000 4.000 6.000 8.000 10.000 12.000 14.000

2012

2013

2014

2015

2016

3D Seismic Survey

KM

2

0 20 40 60 80 100 120

2012

2013

2014

2015

2016

actual

Drilling of Exloratory Wells 2012 - 2016

wells

0 200 400 600 800 1.000 1.200 1.400

2012

2013

2014

2015

2016

Oil Production 2012 - 2016

MBOPD

0 1.000 2.000 3.000 4.000 5.000 6.000 7.000

2012

2013

2014

2015

2016

Gas Production 2012 - 2016

MMSCFD 8.000 9.000 0 5 10 15 20 25 30

2012

2013

2014

2015

2016

Firm Commitment

BL

OCKS

Exploration Block Firm Commitment

0 100 200 300 400 500 600

INDONESIA

Conventional Oil and Gas Bidding First Round

2017

Direct Proposal Tender

Direct Proposal shall be carried out in the joint study framework either by enhancing data quality and or conducting survey for additional data. All risk and cost shall be borne to business entity / permanent establishment requirement to submit.

Performance Bond in the amount of US$ 1.000.000 for joint study.

1

2

3

4

5

6

7

8

9

10

11

12

13

Investor’s proposal Investor’s proposal for open acreage or available block shall describing area boundaries with geographical coordinates, short geology report, data

completeness, profile and

capability of the company if within not later than 14 calendar days after the receipt of submitted proposal from Business Entity (BE) or Permanent Establishment (PE), there are any other BE or PE submitting proposal for direct proposal of an area in which:

Cover more than 25% from previously proposed, the whole areas will accordingly be reserved for the tender Cover less than or equal to 25% from the previously proposed, the sub-sequent BE or PE shall adjust the proposal with the proposal of previous BE or PE

Determined by Minister of Energy and Mineral Resources (MEMR) Minister (MEMR) determine the acreage of tender including boundary of acreage, term and condition of cooperation contract and issues Direct Proposal Document.

Direct Proposal Document

It contains information of tender procedures, schedules, data access procedures, technical information of working acreage, PSC draft and other requirements. The intended participant must purchase the Direct Proposal Document at MIGAS.

Clarification Forum

Participants who have obtained the Direct Proposal Document may submit questions regarding tender process.

Evaluating of Participating Documents

Participating Document will be assessed based on the technical criteria of 3 years exploration commitment,

financial capabilities and

company performances, as proposed by bidder.

Contract Signing SKK MIGAS and Contractor sign the cooperation contract

Evaluation of Proposal The committee evaluates the proposal submitted by company for open acreage and available blocks. The Director General of Oil and Gas may approve proposal of joint study based on the evaluation of the

Joint Study Joint Study will be conducted between MIGAS and BE/PE.

Result of Joint Study The Committee evaluates the result of joint study in the technical and economical aspect.

Announcement The new acreage will be announced through electronic and other media (our Website: http://www.migas.e sdm.go.id)

Data & Information It is mandatory that any participant will have to purchase an

oicial government

data package through and set by MDM prior to submitting the participating document.

Determination of The Wining Bidder The Minister (MEMR) will appoint the winning bidder, based on the committee recommendation. Participating Document

The tender participant should submit the entire Participating Document on the closing date of the tender.

Regular Tender

Blocks from open acreage prepared and designated by MIGAS Available Blocks

1

2

3

4

5

6

7

8

9

Determined by Minister of Energy and Mineral Resources Minister (MEMR) determine the new acreage for tender including boundary of acreage, term and condition of cooperation contract and bid documents.

Announcement The new acreage will be announced through electronic and other media (our Website: http://www.migas.esdm. go.id)

Bid Documents It contains information of tender procedures, schedules, data access procedures, technical information of working acreage, PSC draft and other requirements. The intended participant must purchase the Bid Document at MIGAS.

Clarification Forum Participants who have obtained the Bid Document may submit questions regarding Tender Process.

Evaluation of Participating Documents

Participating Document will be assessed based on the technical criteria of 3 years exploration commitment), financial capabilities, and company performance, as proposed by bidder.

Contract Signing SKK MIGAS and Contractor sign the cooperation contract.

Data and Information It is mandatory that any tender participant will have to purchase an

oicial government data

package through and set by MDM prior to submitting the participating document.

Participating Documents The Tender Participant should submit the entire Participating Document on the closing date of the tender.

The Minister (MEMR) will appoint the winning bidder, based on the committee recommenda-tion.

Terms & Conditions

1. 2. 3. 4. 5. 6. 7. 1. 2. 3. Andaman I Andaman II South Tuna Merak Lampung Pekawai West Yamdena Kasuri III Tongkol East Tanimbar Mamberamo 7,346 7,399.85 7,827.09 5,104.17 7,775.83 8,209.96 752.39 583.98 8,242.81 7,783 35 35 40 25 35 40 5 5 40 35 57 57 57 57 57 57 57 57 57 57 52 52 52 52 52 52 52 52 52 52 43 43 43 43 43 43 43 43 43 43 48 48 48 48 48 48 48 48 48 48 750,000 500,000 500,000 500,000 500,000 500,000 500,000 500,000 500,000 750,000

G&G Study and 3D Seismic Survey 500 km2

G&G Study and 3D Seismic Survey 500 km2

G&G Study and 2D Seismic Survey 500 km

G&G Study and 2D Seismic Survey 500 km

G&G Study and 1 Exploratory Well G&G Study and 2D Seismic Survey 1000 km

G&G Study and 1 Exploratory Well Block

No Size

km2

Terms and Conditions Gross Split PSC 1st

Relinquish-ment

(%)

Government Base Split (%)

Contractor Base Split (%)

Oil Gas Oil Gas

Minimum Bonus

(US$)

Minimum Firm Commitment

A. Direct Proposal

B. Regular Tender

G&G Study and 1 Exploratory Well G&G Study and 2D Seismic Survey 1000 km

G&G Study and 2D Seismic Survey 1000 km

Tender Schedule

Access Bid Document : May 29 - July 10, 2017

Clarification Forum : June 5 - July 12, 2017

Bid Submission : July 17, 2017

Access Bid Document : May 29 - September 15, 2017 Clarification Forum : June 5 - September 18, 2017 Bid Submission : September 25, 2017

A. Direct Proposal

Document Preparation Payment to Bank

$

Go to http://e-wkmigas.esdm.go.id

for registration “BPN 019 Ditjen Migas Valas.

Account Number 0378-02-000068-30-8 Bank Rakyat Indonesia (BRI) Branch: Jakarta Rasuna Said. Swift Code: BRINIDJAXXX" - Copy of the notarized dead/articles

of establishment/incorporation - NPWP

- Company domicile letter - etc

Registration and payment Validated Username & Password

Download Bid Document from http://e-wkmigas.esdm.go.id

Bid Document Access

Bidding process is using “e-lelang wilayah kerja” application at: http://e-wkmigas.esdm.go.id

Guidance booklet should be read first before make any payment for Bid Document.

You may download the guidance from the website. Steps for accesing Bid Document

Data Access

Bid Participants shall access geological & geophysical data, which will be used for technical evaluation of the exploration work program.

A. Data package consists of geological & geophysical data and outside which are directly related to the block. The data package is mandatory, it shall be accesed at:

Pusat Data dan Informasi (PUSDATIN) KESDM Executing Agency MIGAS Data Management (MDM) PT. Patra Nusa Data

Graha Elnusa 5th Floor JL.TB Simatupang Kav.1B Jakarta 12560

(Ph. 62-21-7816770-74 Ext.15, Fax. 62-21-7816775 )

B. Auxilliary Data: consits of geological & geophysical data related to areas but not covered on the Data Package. The Auxilliary data is optional (not mandatory) it can be accessed from legal sources:

1. PT Patra Nusa Data

2. Speculative Survey Companies 3. PPPTMGB “LEMIGAS”

Jl.Ciledug Raya Kav. 109, Cipulir Kebayoran Lama Jakarta Selatan 12230

Contact: Koordinator Kelompok Riset Teknologi Eksplorasi 4. Badan Geologi

Jl. Diponegoro 57, Bandung 40122 Contact: Sekretaris Badan Geologi 5. Puslitbang Geologi Kelautan

ANDAMAN I BLOCK

The Andaman I Area is located on the northernmost ofshore Aceh, the relative was on the international border between Indonesia and Thailand. The area covers an area of

7346 km2. Andaman I locations in geological, located in the Andaman Sea in the North Sumatra Basin. In the west, North Sumatra Basin ridge bounded by Sea Mergui and in the north, it is bordered Sub-basin Mergui. Exposure Mergui and Malacca became the boundary in the east and south of the mainland portion of the North Sumatra Basin. Exploration in the area Andaman I was very attractive, given its location relatively close to the North Jambu Aye-1 which is a well with a hydrocarbon discovery of two reservoir intervals.

STRATIGRAPHY

Sequence stratigraphy

ofshore North Aceh

and Mergui Basin

based on well data and seismic 2D shows the condition of the ocean basins, continental slope

and shallow current

exposure. Stratigraphy in the southern part of the Basin Mergui or of the coast of North Sumatra is very diferent from the situation in the southern part of the stratigraphic

North Sumatra

dominated by coarse clastic terrigenous.

PETROLEUM SYSTEM

Source Rock

Candidates source rock in Andaman I is projected to come from shale interval Bampo and Lacustrine Shale-fill Parapat. Based on Fuse et al. (1996), Parapat Shale is only found in the Deep Sea Bayu-1. The well-Holland Jambu Aye record source rock interval is thinner. These conditions explain that Parapat Lacustrine facies distribution, and localy limited in some areas. As with the shale

interval encountered

Bampo widely distributed.

Some wells indicate that the source rocks, both Bampo and Parapat, composed of kerogen type II / III which tends to be dominant producing gas. It also indicated happen suppressed vitrinite relectance value. Deep Sea Bayu-1 record the vitrinite relectance values reaches a maximum at a depth of 3053 m, whereas the Tmax and the temperature at the same depth indicates the condition of the source rock that has entered a phase of oil generation.

Reservoir Rock

Potential rock reservoirs in Andaman I targeted from three intervals, namely: Sandstone Formations Parapat Late Oligocene, Early Miocene Sandstone Bampo, and Sea Fans in the Middle Miocene Formations Baong. Rock properties of the reservoirs is obtained from wells Deep Sea Bayu-1 which is located closest to the block boundary Andaman I. Based on petrophysical analysis, porosity Sandstone Formation Parapat is good porosity.

Migration Time

Burial history reconstruction built to be able to interpret and evaluate the potential, maturity and petroleum generation. Reconstruction is based on data Pseudowell 2 (PS2) located in the north central part of the basin (depocenter). The result says that oil from oil shale Bampo start entering the window when the Pliocene, while the gas phase window begins on Early Pleistocene. The top of the formation Parapat has entered the oil window since the Middle Miocene with lithology composed of Lacustrine facies. Migration of hydrocarbons derived from depocenter / kitchen in the north. Kitchen in the southern area obstructed by structures trending northeast-southwest so that the migration of hydrocarbons cannot reach and fill existing closure. Lead-lead of Parapat

interval are presented in two diferent kinds of hydrocarbon charging scenarios, namely: 1) a hydrocarbon derived from shale interval Parapat and 2) a hydrocarbon derived from shale interval due to juxtaposition of Bampo fault that forms the conduit. Lead-lead Bampo interval has a greater opportunity to be filled by hydrocarbons from shale Bampo-I cross section showing petroleum play in Andaman I.

Trap

Rock lithology-hood in Andaman I is composed of fine sized rocks that are distributed widely in the area. Shale rock formations hood comes from the lower Miocene Keutapang, Shale Formation Belumai and Flakes Bampo top.

Trap mechanism formed in Andaman I is the result of a structural trap faulted anticline and anticline four-way dip restricted some fault. Trap geological structure was formed when the expansion of the Andaman Sea and the appointment of Barisan in Late Miocene to Plio-Pleistocene (Sosromihardjo, 1988).

ANDAMAN II BLOCK

The Andaman II Block Area is located in North Sumatra Basin, it consists of a series of horst and graben structures mostly walked toward the N-S. The horst and graben structures are considered as a potential kitchen available and trapping areas. The

total acreage for Andaman II Block is 7399.85 km2, with water depth ranging from

250m–1250m. Towards the ofshore, the area is still underexplored due to its location in the deep water. The presence of similar geological condition between onshore and ofshore areas has given good potential of the extension of onshore basin North Sumatra to the northern part in the ofshore Areas. There are 94 seismic lines data with total length of 8950 km and one (1) well located inside the Andaman II Block.

PETROLEUM SYSTEM

The activity of tectonics in North Sumatra Basin during the Pre-Tertiary was very pronounced as compared to tertiary time. Volcanism coincident with intrusive activity was also present in relevancy to the tectonic activity and commonly produced acid intrusive such as granodiorite and granite.

During the tertiary the tectonics activities are basically diferentiated into Pre-Miocene and Miocene to Post Miocene. The Pre-Miocene tectonics mainly produced the N-S structural pattern. The dominant fault zone is the so-called “98 fault zone” located around longitude 98° and trending in an N-S direction. The Miocene and Post Miocene structural pattern is mainly a NW-SE orientation relevant to the Bukit Barisan uplift. The stratigraphy sequences of North Sumatera Basin can be closely compared to the tectonics event. On the basis of this relationship, the tectonostratigraphy of North Sumatera Basin can be divided as; 1. Basement; 2. Early Syn-Rift (Bruksah & Bampo Formations); 3. Late Syn-Rift to Transitional Phase (Belumai & Peutu Formations); 4. Syn-Inversion Regime (Keutapang & Younger Formations).

Based on biostratigraphy analysis, the following the biozonation of blow (1969), the analysed of Bayu Laut Dalam (BLD)-1 well interval (1870–3086m TD) range in age from Late Miocene–Late Oligocene, without any major missing sections. The interpreted depositional environments are deep marine (bathyal) and the later is neritic ot supralitoral. For detailed information, refer to biostrat report of BLD-1 by Geoservices. One (1) core sample from the Bampo Formation from depth 2623m showing visible porosity of 11.6%, classified as sublitharenite. The other five (5) core samples were from the Parapat Formation, ranging from 2755m–2887m showing visible porosity range from 14.4% - 18% classified mostly as subarkose.

The SouthWest to Northeast profile shows the stratigraphy correlation of well GLM-1, EAO-1, SML-1 & BLD-1. From the correlation, shows that the area in the Samalanga-1 well is in the deep area and become higher to the southwest and northeast to BLD-1 well. The structural correlation also showing the same position with stratgigraphy correlation, it mean that the lower/deep area is located in the southwest of the Andaman II Block. Based on the post mortem analysis there is no no-significant oil and gas show was encountered & high risk gas peak readings while drilling range from 0.3–0.7 %. All reservoir facies identified were water saturated. No C5 was detected in Bampo Sandstone and no C4 was detected in Parapat Fm. The main reason why BLD-1 is dry is related to the time of migration and lack of source rock.

The overall 2D seismic quality generally from medium to good. BLD-1 was supplied with velocity survey, the check-shot data will be used tie the seismic and well data. The horizon picking was conducted based on the formation top which was taken from the tied well into seismic data. There are five (5) main important picks; they are Pre-Tertiary Basement, Top Parapat, Top Bampo. Top Belumai and Top Baong. It was later become a basis for picking the top horizon and mapping. There two (2) pattern of tectonic activities in the North Sumatra Basin, basically diferentiate into Pre-Miocene and Miocene to Post Miocene. The Pre-Miocene tectonics mainly produced the N-S structural pattern and

the Miocene and Post

Miocene structural

pattern is mainly a NW-SE orientation relevant to the Bukit Barisan uplift.

The base source rock interval in the Andaman II Block is within the

Parapat & Bampo

Formation, in the

mudstones deposited in the rift graben axis. The main reservoir intervals in Andaman II is within the Parapat and Bampo Fm, presents in rift basins as luvial to alluvial fan facies. Where the Belumai and Baong is poorly developed in this area. The seal are overlain by impermeable shale sequences of Lower Baong & Ketapang shales and from intraformational of Bampo Fm sub-regional seal, developed in the post-rift deposition.

DATA AVAILABILITY

.

SOUTH TUNA BLOCK

The South Tuna area, is located in the ofshore of East Natuna Basin, covers

approximately 7827.09 km2_{. The area is geologically located in the back-arc region of}

East Natuna, but had experienced several tectonic regimes previously. East Natuna region has been subjected to a series of complex plate movements, which have much inluence on the development of the petroleum habitat of the area. The relatively close proximity of Sarawak orogeny has made the area especially prone to the efects of rift, drift and collision events which in turn control the development of potentially important petroleum plays in the region.

Hydrocarbon discoveries and shows from the well drillings in the whole East Natuna have convincingly indicated that hydrocarbons have been generated in the region and its surroundings.

Reinterpretation of old data (surface and sub-surface), and assessment of hydrocarbon plays using newly developed concepts, may result in a new understanding of the geologic history of the basin and previously unrecognized hydrocarbon systems can be deduced. Hence, new leads and prospect areas previously overlooked may be exposed.

PETROLEUM SYSTEM

By far the best source rock potential in the East Natuna Basin, lies within the Late Oligocene section which is only penetrated by three (3) wells; Cipta A-1, AT-1X and Panda-1 (based on corelab data). The Early Miocene displays fair source potential, with numerous samples attaining better than 1% TOC. Geochemical data from Cipta A-1 showing the possibility for Cretaceous section as possible source rock. The best source potential is occurring in the Bunguran Trough & Sokang Sub-basin, whereas the Komodo Graben is still immature for source potential.

To date, hydrocarbons, mainly gas but some oil, have been found in both clastic and carbonate sequences. The gas reservoirs developed in the Tertiary Terumbu carbonates

often contain a high percentage of Carbon Dioxide (CO2). Discoveries made to date have

identified accumulations only in tertiary reservoirs, with the Middle to Late Miocene section, both clastic and carbonate, proving particularly fruitful. Shallow marine to deltaic environments have given rise to fair to good quality clastic reservoirs, although some potential also exists in reworked sediments with deeper water, turbiditic ainities. No pre-tertiary (basement) reservoir levels have been identified in the region and there is believed to be little future potential at these low stratigraphic horizons. The oldest tertiary sections, the Oligocene section likewise has provided little exploration encouragement to date, although this level has only been penetrated by only three wells. Younger tertiary sediments, the Arang Formation indicate locally encouraging petrophysical characteristics in clastic reservoirs and these stratigraphic levels (together with the Terumbu carbonates) remain the most promising for future exploration activity and success.

Source Rock

The overall source rock potential of the area is generally rather poor. Generally, the Arang and Gabus Formation shales in the South Tuna Area are generally poor source quality, with better potential further northeast. In the South Tuna, the area gas prone

source rocks predominate over any oil sources

The Cretaceous section were penetrated by Cipta A-1 showing that the section could become possible source rocks in the South Tuna Area, where the distribution only in the deeper area (Komodo Graben).

The sequence Oligocene could also become potential source rock in South Tuna Area, the BEICIP report (1985) notes that the Gabus formation represents the first transgressive phase over Basement & the Barat Shales as the period of Maximum Flooding. The section is dominated by continental to littoral deposits in Cipta A-1.

The Miocene section consists of sandstone and shale inter-bedded with some coals deposited in deltaic or paralic environment. Geochemical analysis indicates that the SB1 (Early Miocene) section has a fair to good organic richness with mainly kerogen type III that generated oil and gas prone. The Plio-Pleistocene sediments are probably still immature, although subsidence and rapid sedimentation occurred in the eastern parts of the basin.

Reservoir Rock

To date, hydrocarbons, mainly gas but some oil, have been found in both clastic and carbonate sequences. The gas reservoirs developed in the Tertiary Terumbu carbonates

often contain a high percentage of Carbon Dioxide (CO2). Late Oligocene sands are well

developed in several wells (Cipta A-1) & sequence stratigraphy shows that the Early to Middle Miocene Barat & Arang formations extend across the South Tuna Block. Porous foreshore, estuarine and bar sands characteristic of the Barat are producing reservoirs in nearby fields and could become target in the South Tuna area.

The Terumbu (carbonate) reservoir reef facies is proven as an excellent reservoir and contains gas and oil accumulations in several adjacent fields including the giant Natuna D-Alpha gas field immediately to the east.

Migration Time

East Natuna Basin in the Late Cretaceous epoch is part of a basin behind the arc, which extends from ofshore Vietnam, cut the Natuna waters and extend into Sarawak. This basin is composed by Komodo Sub-basin and Sokang Sub-basin in the western part and Natuna eastern in the East. Sub-basin in the west and in the east it is separated by a Paus Ranai ridge. Sokang Sub-basin in the southwest of the East Natuna Basin has thickness sediments up to more than 6000m of tertiary age. In the north of Sokang Sub-basin there are Komodo Sub-basin, which is a graben, and have the Miocene clastic sediment thickness of up to 5000m. The northern part of East Natuna Basin, there is sediments of Neogene age, including reef facies carbonate Miocene to Pliocene with a thickness of up to 1500m.

Extensional tectonic phase known as phase sag forming normal faults trending north - south as a block fault and half graben. East Natuna Basin began to form in the Oligocene which then began to fill with sediment. This extension basin formed by the movement

of Malay Peninsula and the Sunda Shelf, followed by the Late Miocene compressional phases that lead to tilting and folds associated with shear fault.

The history of the formation of Natuna Basin can be divided into five stages, namely:

1. Cretaceous-Eocene, East Natuna Basin development.

2. Early Oligocene - Late, Gabus Formation deposition in both basins. 3. Late Oligocene - Early Miocene, Arang Formation deposition.

4. Middle Miocene - Late Miocene, sedimentation Arang Formation and Muda Formation in the West Natuna, precipitated carbonate reefs in East Natuna. 5. Pliocene - Pleistocene, more precipitation in the shallow sea of Muda Formation in

western and eastern Natuna, where China Basin remains at sea sediment.

The western part is dominated bytertiary sediments were very thin coat of local igneous rocks, metasedimen, and Tertiary metamorphic rocks. Paleotopografi Positive Pre-Tertiary events are a major factor describes the layers of sediment. Trend trending half graben NSW-SSE, and the lack of continuity of the character of the region Komodo Graben.

Innermost part of the graben is predicted to have a depth of 5000m. Trough Sokang same as the Komodo Graben but has depocenter deeper. Furthermore, the structure of roll over and some of the common faults found in graben.

Subi Shelf which is located between the East Natuna Arch and Bunguran Trough has the characteristics of sediment relatively shallow, and is dominated by clastic sediment. Moreover, in the north-eastern part, clastic sedimentation replaced by the development shelf of carbonate shelf facies, with local reef in some parts.

On the eastern side of the ridge there Trough Sokang Paus-Ranai-Tuna. As Natuna Arch, this ridge NNW-SSE oriented, with a limit of the western part of the steep and faulted and the east side is faulted, structural developments seen in the formation of sediments with diferent compaction of the Tertiary sediments.

Bunguran Trough located in the east of Subi Shelf (Reef Carbonate Shelf) and Paus Ridge-Ranai, and the depth increases toward the main part of the regional Basin Sarawak. Trough has a great thickness of sediment Pliocene and Pleistocene.

Regional stratigraphy, which developed in the East Natuna Basin and West Natuna directly related to tectonic phase formed, so that it can be divided into four (4) tektonostratigraphy:

1. Syn-Rift: formations syn-rift is Lama Formation and Benua Formation Late

Eocene-Early Oligocene. Lama Formation is composed of lake sediments, luvio-deltaic and alluvial fan. This sedimentary rock fill Terban half (half graben) the process associated with the expansion of the ocean loor. Sandstone layer of sediments is producing gas and oil. Benua formations dominated by the shale, which is deposited comformity on top Lama Formation.

2. Post-Rift: developing sediment is sediment of lacustrine and luvial. Fluvial sediment thickened to depocenter and developing of meanders facies to bradded stream facies ended Late Oligocene. From old to young post rift is comprised of

Gabus Formation Under section compiled by intercalation sandstone and shale with luvio-deltaic facies. Furthermore, shale with Middle-Upper Oligocene of Keras Formation is deposited conformity intercalation of sandstone and shale deltaic facies, bradded stream and lacustrine from Gabus Formation section on the Late Oligocene-Early Miocene.

3. Syn-Inversion: Tectonic inverse to the Late Oligocene-Miocene epoch the end result in the formation of graben and half-graben history, located in the North Kakap and South Kakap, growing upwards forming the Sunda Fold. From old to young, syn-sedimentary inversion is organized by the Barat Formation shale deposits Early Miocene. Followed by the deposition of shallow marine sandstone Pasir Formation and tidal lat sediment, swam, and shallow marine of Arang Formation. Barat Formation sandstones and Pasir Formation is a reservoir hydrocarbon.

4. Post-Inversion: Top Arang Formation depositional uncorformity mudstone, shale and sandstone Late Miocene-Resen with shallow marine facies of Muda Formation. In the East Natuna Basin, sedimentary Late Oligocene-Early Miocene sequences composed by sandstones at the bottom, and shale on top. Sandstone sequence equivalent to Upper Gabus Formation and shale sequences equivalent to the Barat Formation on the West Natuna Basin. Later on it was deposited in conformity sandstone Arang Formations consisting of sandstones and alluvial deltaic, followed by the deposition of shale Arang formations under section consisting of green shale of maximum transgression sequences and last deposited sandstone Sokang Formation Early Miocene-Middle Miocene.

In the northern part of the East Natuna Basin, lithology that lay shale Arang Formation is part Bottom Terumbu Formation. The lower part is composed by wackstone,

packstone, and boundstone of an exposure, while the upper part of the dolomite prepared by reef built-up, shale marine and marls. Local unconformity is found among the two lithologies, marks the end of a regressive phase.

Trap

Regional bathyal Muda shales provide adequate seal for the reservoirs in South Tuna

Area

Most of the hydrocarbons accumulations are trapped in the structural closures such as four-ways dip anticline, inverted anticline, rotated fault blocks, as well as combination structure and stratigraphic closures.

MERAK LAMPUNG BLOCK

The Merak Lampung Area is located dominantly in Sunda Basin. Administratively, most

of the area is located in Banten province, with a total acreage of 5104.17 km2_{, consisting}

of onshore (54.5 %) and ofshore (45.5 %) area. This area is considered to have good potential for hydrocarbon and because it has been proposed for the oil and gas. Merak Lampung Area into proper subsurface configuration, identifying its tectonic dynamics and evolution to achieve a proper petroleum system evaluation with emphasizes on source potential, optimum reservoir and structural trap integrity. Sunda Basin is the southern part of Sunda Craton which is classify as one of tertiary back-arc sedimentary basins situated in north or northeast of the present day volcanic arc (Wight et al., 1986). It extends for approximately 90 miles in a north-northeasterly direction from northeast of Merak Lampung. The shape of basin roughly form a triangular, the apex facing south-southwest towards volcanic cone at east Merak Lampung. The basin bounded by Hera and Asri basins in north-northeast, Lampung High in western part and Seribu Platform in eastern part.

PETROLEUM SYSTEM

Source Rock

Sunda Basin is a mature basin for exploration and the remaining efort can gain from a better understanding of the hydrocarbon generation and migration timing system present. This basin has a good database for such an approach. Since 1970 there have been 165 wildcat wells drilled, 16 fields developed and more than 550 MMBO produced. The potential source rock assemblages are penetrated by many wells around all but the deepest parts of the depocenter. The basin also has an extensive coverage of seismic data, tied regionally and supported by good bio-stratigraphic age control for the Miocene. The Talang Akar and Banuwati formations are poorly constrained in terms of age, but this does not appear to have a significant efect on the timing of source rock maturation.

Reservoir Rock

The source system of the Talangakar Formation can be divided into two parts. The first of these is shown on the model as both a luviatile and paludal shale source rock, and an under compacted migration seal in the central part of the basin. It is poorly drained, and primary hydrocarbon migration is incomplete. The second group comprises similar but normally compacted shales interbedded within the luviatile sandstone reservoir system. These are not well illustrated on the simple model, but because they are mature, richly organic, and widely distributed among the reservoir rocks, they are clearly an important source system. Coals interbedded within the luviatile sequences are also likely to have generated oil, but they are not abundant. Talangakar shales is potential for source rock and regionally is proven source rock. Talangakar Formation has good–excellent TOC with kerogen type II (Mixed oil and gas). Marine claystones and mudstones of the Airbenakat and Cisubuh formations complete the regional vertical seal of the Sunda Basin. The most important migration system in the Sunda Basin consists of the multifarious braided stream, point bar, and distributary channel deposits of the Talangakar Formation.

Reservoir at Talangkar Formation with Oligocene-Early Miocene age, Baturaja Formation Early Miocene age. Reservoir quality relatively poor. Seal found in the area at Cisubuh Formation and then the main leads have been faulted. Traps in the pitfalls that occur in this area is structural traps like faulted.

Migration Time

Stratigraphy analysis has been identified some marker like Sequence Boundary (SB) and Maximum Flooding Surface (MFS) from Pre-Tertiary to Pliocene. The lithology that has been identified ranges between igneous rock, sandstone, limestone, claystone and siltstone. Based on biostratigraphy analysis, the following the biozonation of blow (1969), there are two type logs that had been determined Surti-1 & Utari-4. These wells penetrate ranges from Pre-Tertiary to Pliocene. These type logs are profile model of depositional environment and sequence correlation in Merak Lampung Area.

Trap

The Merak Lampung Areas proper subsurface configuration is identified by its tectonic dynamics and evolution to achieve a proper petroleum system evaluation with emphasizes on source potential, optimum reservoir and structural trap integrity. Reinterpretation of old data (surface and sub-surface), and assessment of hydrocarbon plays using newly developed concepts, may result in a new understanding of the geologic history of the basin and previously unrecognized hydrocarbon systems can be deduced. Hence, new leads and prospect areas previously overlooked may be exposed.

PEKAWAI BLOCK

Pekawai Area is located in South Mahakam area, ofshore and onshore of East Kalimantan, Indonesia. It consists of nine sub-blocks with total area are approximately

7775.83 km2. Pekawai area is relatively adjacent to oil and gas production fields in both

Mahakam and South Mahakam area.

Sub-block B area, as the northernmost sub-block in Pekawai, is close to giant Peciko gas fields (discovered in 1977). Several gas and condensate fields, such as Jumelai (1975), Stupa (1996), Jempang (1990) and Metulang (1998) are near to sub-blocks of C, F and G. Later discoveries in above 2000’s, such as Jangkrik-1 (2009; oil-gas on Miocene-Pliocene turbiditic sandstones as channel slope) and Merakes-1 (2014; gas on Miocene-Pliocene turbiditic sandstones interpreted as submarine fan) prove that exploration within study area is still viable.

PETROLEUM SYSTEM

Critical moment of Pekawai is considered to be timing of gas expulsion as an aspect of migration. Both Late Eocene interval (S1) and Early Miocene (S2) has Pliocene (around 3 mya) for their timing of gas expulsion as the last petroleum element that is established. Three petroleum plays are regarded as having the best chance of finding commercially viable quantities of hydrocarbons in Pekawai: (1) Sepinggan Fault Play, (2) Carbonate Build-up or Pinnacle Play and (3) Anticline associated with Toe-Thrust Play.

Source Rock

Based on integrated geochemical study, three potential source rocks could be identified within Pekawai. Detail of each source rocks as well as burial history can be described as follows:

1. Late Eocene interval (S1), equivalent to Tanjung or Kuaro Formation that has

deep-water facies of shale with inlux from terrestrial. It has kerogen type III; TOC average of 0.52 wt%; HI is up to 87 mg/g (refer to Rinjani-1). This source rock has reached gas expulsion in Pliocene (3 mya) with threshold depth around 12,000 feet interpreted source pod near to LL-1 lead.

2. Early Miocene interval (S2) composed of shale in delta front to open marine facies. It has kerogen type II/III; TOC is up to 47.34 wt%; HI range is 65 - 380 mg/g. This interval is believed as main source rock to South Mahakam proven oil and gas fields. It reached its gas expulsion in South Mahakam depocenter during Early Pliocene (3 mya) with threshold depth around 16,400 feet.

3. Pliocene interval (S3) consists of coaly and laminated shale facies. It has kerogen type II/III; TOC is up to 3.21 wt%; HI is up to 365 mg/g. This source rock acts as biogenic type that anticipated producing gas.

Reservoir Rock

Regional geological review, petrophysical analysis as well as closure identification established in this study conclude that six reservoirs are potential for further investigation as follows:

1. Early Miocene Labangka interval (R1) mainly consists of skeletal packstone

to wackestone that can produce initial 150 MSCFGPD even with 0.0015 mD permeability (based on Bebulu-1 DST-3). A petrophysical analysis in several well targeted this interval suggested avg. NTG of 0.019–0.22 and avg. PHIE of 0.126–

0.170 (fair to good quality).

2. Late Miocene interval (R4), equivalent to Barokah limestone in SIS-A#1, is dominantly composed of wackestone–packstone facies that lowed gas around 18 MMSCF (DST-1). This interval has up to 86 feet of gross thickness with NTG in range of 0.341–0.762 and PHIE in range of 0.177–0.346 (good to excellent quality7). 3. Late Miocene Lower Apar interval (R6) mainly consists of limestone with mud

mound facies (based on SWC in Apar-1 well). RFT in Apar-1 result shows 1.7 cuft gas and trace oil. A petrophysical analysis conducted in this interval suggested tight carbonate with very low avg. NTG (0.001–0.028) and relatively poor PHIE (0.100– 0.161).

4. Late Miocene Telakai interval (R8), identified in Telakai-1 FIT test data, is dominantly composed of limestone (possibly slope facies) with up to 144.36 feet of gross thickness. It has NTG in range of 0.047–0.450 and PHIE in range of 0.157–0.251 categorized as fair to excellent quality (calculated from Apar-1 well).

5. Latest Miocene to Pliocene? of Low Resistive interval (R9) mainly consists of pinnacle reef facies (clearly seen in seismic data). Based on analogue lithology to Mandu-1 well (bio-clastic calcarenite to calcilutite and 242.78 gross thick), it shows good petrophysical analysis with high avg. NTG (0.706–0.978) and relatively good to excellent PHIE (0.178–0.270).

6. Pliocene Sidi interval (R10) mainly consists of sheet and turbiditic sandstone that has MDT-1 sample of dry methane gas (possibly biogenic) in Sidi-1 well. A petrophysical analysis in this interval suggested maximum gross thickness can reach up to 275 feet while avg. NTG of 0.608–0.750 and avg. PHIE of 0.258–0.366 that categorized as excellent reservoir quality.

Migration Time

Regional stratigraphy of Pekawai can be divided into three groups. Sub-blocks I can be referred to Sebuku area by Pireno and Darussalam (2010) that is mainly focused on Eocene and Oligocene strata as petroleum target. Stratigraphy of South Mahakam was adapted from Ardhie et al. (2013) especially in post Oligocene (Miocene to Recent). Validation and reservoir identification refer to several key wells as reference for Pekawai. Eocene interval (Hz-01) comprises a rifting in-filling stage with the siliciclastic sand and shale of lacustrine and luvio-deltaic environment equivalent to non-marine Tanjung Formation that lies above basement (Pireno and Darussalam, 2010). This interval is also known as Kuaro Formation, which has similar age.

Oligocene-Earliest Miocene interval (Hz-2) is mainly carbonate-dominated equivalent to Berai Formation. Pireno and Darussalam (2010) reported that this interval appears to have been massive and sudden subsidence after deposition of Eocene interval. It produced more marine sediments rather than clastic during transgression phase. Miocene intervals (Hz-3 to Hz 6) are mostly product of regressive trend that commenced during this stage which created sandier clastic reservoirs that proven as Yakin sands, Sepinggan Deltaic Sequence (Susianto et al., 2012) as well as Jumelai sands (Syarifuddin et al., 2008). In the Middle Miocene to Upper Miocene, transgressive period occurred and produced Sepinggan Carbonate Sequence (SCS) with typically carbonates build-up (Susianto et al., 2012) and pinnacles throughout the area. In Later Miocene, regressive trend re-occurred with the development of low stand delta on top of carbonate sequence

found in Sepinggan Field known as Low Resistive (Susianto et al., 2012). These Miocene intervals are the main targets to sub-blocks within South Mahakam area.

Pliocene interval (Hz-7) consists of sandstone with fine to very fine grained and moderately to poorly sorted, commonly deposited in deepwater settings derived from eastward area. This interval is prolific and proved in deepwater of Kutei Basin such as Ganal and Gendalo field which relatively close to sub-blocks D.

Seal Rock

Identification of seal rock candidates for six potential reservoirs in Pekawai were performed based on its gross thickness and dominant lithology. Those seal rocks are:

1. Early to Middle Miocene of interbedded shale, sandstone and carbonate with 266–

997 feet of gross thick for Early Miocene Labangka reservoir.

2. Lithology of shale dominant and some sandstone intercalations with 550 to 1805 feet of gross thickness for Late Miocene Barokah reservoir.

3. Shale dominant with some sandstone intercalations with up to 2017 feet of gross thickness for Late Miocene Lower Apar reservoir.

4. Lithology of sand dominant with some shale intercalations with 928–1220 feet of gross thickness for Late Miocene Telakai reservoir.

5. Pliocene or younger interbedded shale and sandstone with up to 4300 feet of gross thickness for Latest Miocene to Pliocene Low Resistive reservoir.

6. Pliocene or younger interbedded shale and sandstone with 3927–4677 feet of gross thickness for Pliocene Sidi reservoir.

Trap

Carbonate bank can be clearly observed and identified as trap based on seismic data

in Early Miocene Labangka. It has large area (8.63 km2_{) as well as high vertical column}

(up to 1257 feet). Development of this carbonate bank related to rifting structural grain with relatively NW-SE orientation, similar to Pangkah Graben in Ruby field (Pireno and Darussalam, 2010). Pinnacle reefs also clearly defined as trap, especially in Late Miocene intervals such as Lower Apar, Telakai and Latest Miocene Low Resistive. Its characteristic is local, isolated and scattered throughout area.

Closure LB-1 is typical of fault related closure (3-way dip) that has tilted strata bounded by Sepinggan Fault System and its fault splay. It is included in Jumelai corridor, which already has proven wells such as Jumelai-1, Jumelai-3 and SIS#A-1. NE-SW anticlinal system associated with toe thrust fault derived from development of deep-water setting of Kutai Basin also potential as structural trap, especially in Pliocene sandstone that is similar to proven Gendalo field trap style.

THE WEST YAMDENA BLOCK

The West Yamdena Block located both on onshore and ofshore in Tanimbar Islands

area and covering an area 8209.96 km2 _wide.

The geological history of Eastern Indonesia and the Northwest Shelf of Australia started with the creation of the Australian continental margin in the Permian and Early Mesozoic. This was the result of the Gondwanaland break-up. Following that was a passive continental margin period, which lasted throughout the Late Mesozoic and Tertiary, up until the Late Miocene. Then, a plate tectonic collision had been in progress since the Late Miocene, between the Australian continental margin and Southeast Asian (Banda) arcs.

STRATIGRAPHY

Stratigraphic history of Tanimbar Islands is broadly comparable with Northwest Shelf Australian region. In general, the stratigraphy around the Tanimbar Islands can be subdivided into several mega-sequences, which are clastics and igneous rocks of Proterozoic, clastic and carbonates of Lower Paleozoic, clastics, carbonates and igneous rocks of Upper Paleozoic, clastics of Mesozoic and carbonates and minor clastics of tertiary sediments.

A simplified stratigraphic correlation of the Eastern Indonesia Region.

Charlton (2010) said that Batilembuti Formation exposure location in the West Yamdena Island is the mélange complex area. The mélange zone consists of decimeter-scale lithified blocks enclosed in a non-scaly clay matrix. This mélange complex comprises the superficial accumulation of the ejected mud volcanoes, which are themselves the surface expression of underlying shale diapirs. Active mud volcanoes occur throughout

the mélange belt. The primary constituents of the mud volcano eject a in the Tanimbar Islands are clasts of Mesozoic sedimentary rocks, while the clay matrix is largely composed of disaggregated Jurassic grey shale. Fossil analysis on several rock samples from Batilembuti Formation showed that this formation has Early to Late Pliocene Ages. So we concluded that mélange complex in Yamdena Island were not associated with the former subduction in the area, but act as syn-orogenic deposit along Pliocene Collision. Another chain of islands to the west of Yamdena (referred in this study as the Western Island), are mainly composed of outcrops from Permo-Mesozoic rocks. Cover sequences exposed in these islands range in age from Permian to Miocene, with the Miocene rocks in slightly diferent facies to those exposed in Yamdena. The benthic foraminifera, however, appears to be reworked in turbidite deposits, and are therefore considered more proximal deep marine deposits, rather than shallow marine successions.

PETROLEUM SYSTEM

Source Rock

Hydrocarbon occurrences at the Abadi Field have proved the existence of efective source rock in this area. Regional study have resulted information of potential source rock of West Yamdena Block, which are the Permian, Triassic, Jurassic and Early Cretaceous sediments. And from geochemistry analysis on Tangustabun Clay (Early Miocene), this lithology can be act as fair hydrocarbon source rocks. Basin modeling suggested the Jurassic source rock in the regional Tanimbar Area lying within gas generation zone. Early Cretaceous sediments of Echuca Shoals, Wai Ba and Flamingo Formations suggested being a regional seals in the area. An intra-formational seal are also interpreted to be present in Plover Formation (Early–Mid Jura).

According to the geochemical data of Abadi-1 well, Lynedoch-2 well and Barakan-1 well, there are several Mesozoic sediment interval mentioned above having the capability as a source rock. From geological fieldwork, there are three samples analyzed as source rocks possibilities, but the result is not encouraging. The sample was taken from clay stones of Maru Formation and Ungar Formation. All three samples indicate poor organic matter content of 0.17-0.23%. Organic matter type cannot be defined using Rock-Eval technique, because no HI results available. Data obtained from kerogen typing assessment shows that the sediments contain mainly non-luorescent amorphous and vitrinite materials and may be classified as type III. The sediment maturity seems to indicate immaturity with Ro ranged between 0.38-0.4 %.

Reservoir Rock

Reservoirs are consisting of Lower Cretaceous Ungar quartz sandstone and possible luvio-deltaic/shallow marine sandstone of Plover Formation (Lower–Mid Jura) considered as one of the potential reservoir of the West Yamdena Block. Plover Formation has been proved as the major gas reservoir at the NW Shelf Australia. Petrophysical analysis of Abadi-1 and Troubadour-1 well shows that Plover Formation has 12.6% average porosity. Nevertheless, Middle Jurassic sediment at West Yamdena Block predicted as deep marine deposits.

The other reservoir potential is the sandstone of the Maru (Triassic) And Ungar Formation (upper Jurassic–Lower Cretaceous). Based on field observation, this formation

interpreted as distal turbidite sandstone and from mineralogy composition, these rocks classified as Quartz, Lithic, and Feldsphatic Arenite Sandstone (Gilbert, 1982). Rock physical properties analysis of Maru sandstone indicate porosity ranged from 7.07 to 17.77% and permeability from 2.2 to 46.79 mD. Ungar sandstones have porosity ranged from 8.28 to 23.62% and permeability between 1.36 to 129.51 mD.

Migration Time

Relying on seismic interpretation, well data and regional tectonic, the Jurassic intervals is considered as main reservoir target. The Jurassic interval consists of sandstone unit which was deposited as shore-face to deltaic-luvial deposits. Hydrocarbon came from the Early-Middle Jurassic, Middle-Late Triassic and Late Permian source rocks. The Plio-Pleistocene sediments were not considered source rocks due to maturity issue. Late Jurassic to Late Eocene sequence sealed the Jurassic reservoirs, while the Middle Miocene sealed by Late Miocene to Plio-Pleistocene sequence. The hydrocarbon migrated and accumulated to the trap possibly related to the development of structures.

Trap

Based on regional knowledge, the most common hydrocarbon plays in the NW Australian margin area are structural traps. The main play concept within the West Yamdena Block is fold-related-fault. Four-way dip anticline and three-way dip closures in the area are considered as the main play

The hydrocarbon traps within the West Yamdena Block mainly consist of structural trap of fault block play, which is formed during Paleo-Mesozoic extension and might be reactivated and inverted during the Pliocene Collision due to the locking efect of fold and thrust belt (thick-skinned) force. Early Cretaceous sediments of Echuca Shoals, Wai Ba and Flamingo Formations suggested being a regional seals of the area. An intra-formational seal are also interpreted to be present in Wailuli (Late Jura–Early Cretaceous) and Plover Formation (Early–Middle Jurassic).

KASURI III BLOCK

The Kasuri III block is lies within the Late Cenozoic Bintuni Basin, covers of

approximately 752.4 km2_{. This asymmetric basin is largely filled with Pliocene and}

Pleistocene sediments which underlying Miocene and older sediments dip from west to east. Beneath the Pliocene there are 1000m of limestone and dolomites collectively termed the New Guinea Limestone (NGLG). This group of Limestone comprises the Kais, Faumai and Waripi Formation and these are mainly shallow water marine carbonate containing very few reefs but several levels of extensive cavern development (mainly in Faumai).

STRATIGRAPHY

Bintuni Basin stratigraphy formation begins with the deposition of Kemum the Ordovician age-Devon. Litologinya form of metamorphic rocks. Kemum formation lithology on a bedrock of Bintuni Basin.

In short, based on the correlation of regional and seismic interpretation; the three main periods of geologic history of Eastern Indonesia and Northwestern Australia exposure can be diferentiated as follows.

1. The establishment of the Australian continent limits the Early Permian and Mesozoic. This formation is the result of the break-up of Gondwana with Australian separating continental mass to another, which is now known as the possibility of India.

2. Followed by a period of passive continental boundaries that took place during Late Mesozoic and Tertiary, and constantly until the Late Miocene.

3. Collision of tectonic plates was ongoing at the end of the Miocene between the boundary of the continental Australia and Southeast Asia arc. During this period, the islands in eastern Indonesia that is currently taking shape.

Diferences in depositional environment from shelf to slope and then increases again occurred in the Early Cretaceous. In the Cretaceous, Exposure Northwest and West Papua is characterized by clastic sediment is rich in clay and tertiary sediment is characterized by deposition of carbonate platform (Limestone New Guinea). The total thickness of this section may be more than two kilometers. Both stratigraphic unit was not contained in the Outer Banda Arc, Cretaceous and tertiary sludge is composed of limestone and marl deep water that the thickness of only a few hundred meters away. The spread graben at the Permian-Triassic focused on areas close to the continental break-up line next. On the island of Timor and Ceram and the Banda Arc and Malita Graben Vulcan Northwest Shelf, sediment Permian-Triassic reach a thickness of several kilometers. In West Papua, the distribution of thick sediments of Permian-Triassic is not so well known, but based on well data and seismic information and outcrop data, indicate the presence of at least one of the Permian-Triassic graben. Outside graben, part of the Permian-Triassic thinner and sometimes absent. The available evidence is of the Arafura Shelf which indicates no graben Permian-Triassic in the area.

West Papua has significant sandstone unit in the Cretaceous and Early Tertiary age. In this period, the limits of the continental Australia are generally very stable and not so much experience changes in sedimentation patterns. The origin of the presence of this sandstone is not well documented, but it is assumed that this unit is distinguished from erosional area nearby derived from the results of the local minor tectonic.

PETROLEUM SYSTEM

Source Rock

Regionally, the potential source rocks in Bintuni Basin occur mainly in three zones: Late Permian Ainim Formation continental shales and coals, Early to Middle Jurassic formation restricted marine to continental shales and coals, and Tertiary marine calcareous claystones and limestones of the Waripi Formation and New Guinea Limestones Group.

Late Permian source rocks occur in the uppermost part of the rift sequence and underlie the early post-rift Jurassic gas bearing reservoirs in the Bintuni Bay discovery well. Early to Middle Jurassic source rocks represent the first sediments deposited following

the onset of major transgressive cycle and comprise shales and coals deposited in non-marine to marginal marine environments. Pyrolysis hydrogen indices exhibit major variation (13-313), but are generally greater than 200 indicating mainly humic kerogen maturity but with a significant oil-prone sapropelic component at present day maturity. The Tertiary is not considered a significant source for Kasuri III area because the Jurassic reservoirs, the primary target, are far below any tertiary source. Also, there is no evidence of oil seeps in the Semai (Babo) area. Oil seeps are prevalent in conjunction with the Miocene producing areas.

Based on the available eight (8) wells data, only two (2) wells that have geochemical data which are WOS-1 & ASAP-1 wells. Based on those two data, the potential source rock in the Kasuri III block coming from the Jurassic section.

Reservoir Rock

Mid Jurassic Roabiba sandstone is the major hydrocarbon reservoir of North Kasuri area. Very good sandstone reservoir has been found in Jurassic rock stratum which is the underlying formation of late Cenozoic Bintuni Basin. Most gas of Tangguh area exists in Roabiba sandstone (mid Jurassic) which is of shore face neritic facies; while Ubadari sandstone (mid-lower Jurassic), the combination facies of luvial and marine facies is also the major gas reservoir. The reservoirs have good lateral continuity, porosity and permeability for the absence of Jurassic geotectogenesis in Bintuni Basin. All the exploration activities in this area are centered on Roabiba sandstone.

Although the burial depth is over 4000m, Roabiba sandstone rich in quartzose may have good permeability due to its depositional environment of shore facies, estuarine facies and bay facies. Besides, large amount of abyssal Palaeocene deposit in Daram contains gas-bearing turbidite and Permian Ainim contains large amount of gas-bearing sandstone; they will be converted into efective gas reservoir after thorough fracturing. The Kais Formation is another potential reservoir in the Bintuni Basin. This formation is divided into two members: the porous Kais limestone and the Sekau member which consists of “coral nodular limestones”. Limited oil was produced from the Sekau member but the Kais limestone usually was fresh water bearing, and has poor reservoir quality due to lack of permeability. The other potential is the Lower Steenkool formation that is proven by Kido-1 well.

Migration Time

The relationship between the timing of hydrocarbon generation and migration is important to the prospective of Kasuri III block. Over much of the area, thermal maturation of the Jurassic and Permian source rocks is interpreted to have begun prior to the 3 mya event that formed the prospective structures.

Within the central part of the Bintuni Basin (Berau Bay), the configuration and juxtaposition of the Permian and Jurassic rocks has allowed for a very efective petroleum system to develop. The Jurassic sands typically onlap the Permian Ainim section especially in the deepest parts of the basin where maturity is highest. The tilted fault blocks of the Ainim Formation that underlie the Jurassic have coals, in direct contact with various Jurassic sands as they onlap the Permian. For a long time this configuration has provided a very efective migration route for vast quantities of gas that have been able to pass directly into various Jurassic sands. However tilting of the basin over the last 2 million years has led not only to additional gas generation but also to continued movement of this gas as evidenced by a number of features seen in the nearby Vorwata Gas field.

Large volumes of Permian gas have been generated beneath much of the Bintuni Basin. This gas kitchen lies both beneath and immediately east of the Kasuri III Block. Gas migration has been and still is predominantly directed toward the west and northwest along structural noses and faults. The Kasuri III Block is perfectly placed to receive and to still be receiving much of this gas. The good lateral continuity and permeability of the Jurassic sands has allowed gas to be able to migrate distances well in excess of 50 km.

Trap

The regional seals exist in the Bintuni Basin, the Late Jurassic to Upper Eocene. The Late Miocene and Recent Steenkool claystones, which seals the New Guinea Limestones oil accumulations.

The Jass Formation of Bintuni Basin consists mainly of marine shales and shaly carbonate with numerous thin sandstone beds. This cretaceous marine shale will form an efective seal above Jurassic or older sections.

TONGKOL BLOCK

The Tongkol Block is located in the East Natuna Basin, the area covers 583.98 km2

consists of ofshore with a depth of the sea ranging from 100 meters. It has proven the presence of hydrocarbons. but with moderate risk. There are no facilities around the Tongkol Block.

STRATIGRAPHY

PETROLEUM SYSTEM

Based on seismic interpretation, several play types can be identified in Tongkol Block which consist of Four-way dip closure/Fault Independent-Downthrown and Carbonate Build Up play.

Source Rock

Sample analyses from well data indicate that coals and coaly shales of the Arang Formation in general are the richest source rock in the area. However, they are commonly thermally immature, except in deeper basinal areas where it may become marginally mature, therefore mature source rock expected in the axis of the sub-basin should be done using well results, depositional modeling and seismic data.

Reservoir Rock

The potential objectives of reservoir at Oligocene Gabus sandstone, Lower Miocene Arang sandstone, and Mid-Upper Miocene Terumbu carbonates, and possible fractured Basement. The north-south normal fault trend could provide a good fault-dependent play of both Miocene and Oligocene clastics. Meanwhile the proven build-ups of

Terumbu carbonates could also developed over the Tongkol Block

Trap

Most of the hydrocarbon accumulation are trapped in the structural closures such as four-ways dip anticline, inverted anticline, rotated faults block, as well as combination structure and stratigraphic closures.

THE EAST TANIMBAR BLOCK

The East Tanimbar Block is located in the Barakan Sub-Basin and covers 8242.81 km2_.

It consists of ofshore with a depth of sea ranging from 100 meters up to 700 meters. The study results show the potential of hydrocarbons but with high risk. There are no facilities around the East Tanimbar Block. Includes the frontier category area.

STRATIGRAPHY

The stratigraphy of Tanimbar Block is similar to the Northwest Australian Shelf Basin. In general stratigraphy around Tanimbar basin can be subdivided into two mega-sequences: Pre-rift Mega-sequences (clastic rocks Proterozoic and igneous rocks, sequences of rocks of Lower Paleozoic Down, and Upper Paleozoic) and Tanimbar Basin Mega-sequences (the sequence of Mesozoic and Tertiary carbonate and minor clastics).

PETROLEUM SYSTEM

Indications of hydrocarbons have not been found in the East Tanimbar until now. Several wells drilled in this area (Barakan-1 Well and Koba-1 Well) did not show any indications of hydrocarbons. However, some areas around the East Tanimbar indicate the presence of hydrocarbons, such as the giant Abadi gas field and gas seepage in the Yamtimur area and oil shown in the Arafura-1 wells in the Arafura Basin. The presence of hydrocarbons in the areas around the East Tanimbar provide opportunities that hydrocarbon accumulation has occurred in the East Tanimbar areas.

Source Rock

Refers to the geochemical data of Barakan-1 Well, the sedimentary rocks that take a role as source rock in the East Tanimbar area are Cambrian to Jurassic shales that have approximately 0.48% average total organic content (TOC), with 4 analyzed samples provide TOC of more than 0.5%.

Thermal maturity data indicates that Ro value ranges between 0.67%-0.97% as a characteristic of mature category. On the other hand, the hydrogen index (HI) value is no more than 94 which indicates that kerogen of source rocks is type III (gas prone). Based on the data from analyzed samples with TOC more than 0.5% and RO ranges from 0.67%-0.97%, it can be concluded that shales of Wessel Formation have good potential as source rock. On the other hand, the analysis of field samples indicate that the TOC of the Pre-Tertiary shale ranged between 0.12%-10%, while the hydrogen Index (HI) has a maximum value of 280. This shows that the kerogen from the Pre-Tertiary shales in the Tanimbar Islands are also gas prone (Type III). However, the VR maximum value of the sample field is 0.44 which indicates the thermal maturity level of being towards the mature category.

Regionally source rocks derived from Yura-shale aged land/sea ships equivalent to bottom Plane Formation lakes with TOC average of about 2%.

A good source rock is found at depths of more than 3000m with type III of kerogen (gas prone). The time of hydrocarbon generation is expected to begin at the end of Cretaceous to the beginning of Cretaceous, while gas started to undergo migration at a burial depth of 3400m (Akutsu, 2010)

Reservoir Rock

The most potential rock as a candidate for reservoir are Plover Formation sandstones (Jurassic). This rock has a porosity of 13% with permeability measured in Abadi-1 well of 610 mD.

Another potential reservoir candidate is a sandstone of Cretaceous unit-4 sequence (Albian-Turonian), which is partially volcanic but has porosity around 20% to 25%. Several layers of Late Cretaceous to Miocene sandstones and limestones are also known to have potential as quite good reservoir candidates.

The sedimentary rocks identified as seals in the trap systems are claystones of Middle-Late Jurassic Montara Formation and claystones of Middle-Late Cretaceous Wangarlu Formation. While the potential of claystones from Miocene-Pleistocene Klasafet Formation are still qestionable as there is no tertiary play that have been proven to produce hydrocarbons, although the quite good reservoir and closure structures are identified in the study area.

Traps and Migration

Hydrocarbons Traps in East Tanimbar area are generally estimated as inversion anticlines (Figure-V.6) formed during the Neogene collision phase. The compression forces during these collisions result in reactivation of old structures formed during graben charging (Charlton, 2001), and subsequently produced fold structures that can act as hydrocarbon traps. Stratigraphic traps or combination model of structure and stratigraphy is also estimated to be quite developed, especially in the carbonates build up and pinch-out sands.

Migration path way generally is in the form of a fault that cuts the source rock of hydrocarbon producer and reservoir rock in the trap system and also through the carrier bed that is up dip from source rock to reservoir rock in the trap system.

MAMBERAMO BLOCK

Mamberamo block is located in the Memberamo Raya, Waropen, and Yapen Islands Districs, Papua Province. The block consist of onshore and ofshore area, covers of

7783 km2 area.

Relief of topography and water depth of Mamberamo Block. The relief range from 0-75m. Whereas the water depth range from 0-800m.

The Mamberamo Block is located in the Cendrawasih Basin and Basin of Mamberamo which is a sedimentary basin in the presence of hydrocarbon indications. The position of the Mamberamo Block based on the gravity map is an area that mostly has a low gravity value.

There are several exploration wells indicating hydrocarbon indications of R-1, H-1, Niengo-1, Otus-1, and Gesa-1 & 2 wells. These data indicate that the petroleum system works in the Mamberamo Block.

STRATIGRAPHY

PETROLEUM SYSTEM

Source Rock

the Makats Formation are good and mature rocks, while the Mamberano Formation (Member D) is immature. The HI value <460 indicates the gas category. The spread of Miocene main rock extends to the northern regions until the possibility of mature kitchen area development. The potential is still questionable, however based on Iroran-1 - geochemical analysis, Pleistocene & Miocene section shows up to 2% TOC even more than 2% in Miocene section.

Reservoir Rock

The potential reservoirs are deep marine turbidite of the Plio-Pleistocene Mamberamo Formation. Mid Miocene Limestone of Darante Formation and Plio-Pleistocene Limestones of Hollandia Formation which are deposited on marginal highs and reefs grow as the sea level rise are also possible targets. Fractured Basement are possible reservoirs as well.

Trap and Migration

Rock trap and rock cover migrations built by trap structures (anticlines and fault rises) as well as stratigraphic trap. Stratigraphic trap is seen in sedimentary rocks that mean turbidite and carbonate rocks are thinned to the north. Trap in the formation of the Auwewa Formation, the Darante Formation, and the Makats Formation at Niengo High and onlap formations over the bedrock. Trap structures formed in the fold and cesarean lines rise due to the strong compressional phase of Pliocene and Plistocene which is heading north. The oblique convergence between the Australian and Pacific plates led to the compressional or strike-slip structural features. Regional faults are mostly deep seated faults encouraging rollover anticlines.In the area & surrounding exhibits numerous HC indications, mostly seeps. Migration along fault planes is considered as the primary vertical mechanism.

Gross Split PSC (Regulation of MEMR Number 8/2017)

1. 2. 3. 4. 5. 6. POD I POD II POD F No POD Onshore Ofshore (0<h<20) Ofshore (20<h<50) Ofshore (50<h<150) Ofshore (150<h<1000) Ofshore (h>10000) <2500 >2500 Well Developed New Frontier Conventional Unconventional <5 5<x<10 10<x<20 20<x<40 40<x<60 x>60 Working Area Status 5% 0% 0% -5% 0% 8% 10% 12% 14% 16% 0% 1% 0% 2% 0% 16% 0% 0.5% 1% 1.5% 2% 4%

No. Characteristics Parameters Additional Splits

Field location (h : sea depth in meters) Reservoir depth (in meters) Availability of supporting infrastucture Reservoir condition CO2 content

(x : %)

A. Variable Components

7. 8. 9. 10. x <100 100<x<300 300<x<500 x>500 <25 >25 x<30 30<x<50 50<x<70 70<x<100 Primier Sekunder Tertier H2S content

(x : ppm)

0% 0.5% 0.75% 1% 1% 0% 0% 2% 3% 4% 0% 3% 5%

No. Characteristics Parameters Additional Splits

Crude Oil Specific Gravity (API) Level of domestic components in field of development period (x : %) Production phase 1. 2. <40 40<x<55 55<x<70 70<x<85 85<x<100 100<x<115 >115 <1 1<x<10 10<x<20 20<x<50

Crude oil price 7.5%

5% 2.5% 0% (2.5%) (5%) (7.5%) 5% 4% 3% 2%

No. Characteristics Parameters Additional Splits

Oil & Gas cumulative production

B. Progresive Components

The Contractor obtains an "additional% split" from the split base, depending on the component, as follows:

INDONESIA

Conventional Oil and Gas Bidding First Round

Gross Split PSC Calculator Guidance

(Base Split Contractor for Oil (43%) and Gas (48%)

Block Name :

No. Characteristics Parameters Splits

Working Area status

Field location (if ofshore, sea depth in meters) Reservoir depth (in meters)

Availability of supporting Infrastructure

Reservoir condition CO2 content (%)

H2S content (ppm)

Crude Oil Specific Gravity (API)

Level of domestic components in field of development period (%) Production phase 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

POD I/POD II/PODF/No POD Onshore/Ofshore

<2500 or >2500

Well Developed/New Frontier Conventional/Unconventional

Primier/Sekunder/Tertier A. Base Split

B. Variable Components

C. Progressive Components Crude oil price

Oil & Gas cumulative production

1. 2.

Oil

(43%)

Estimated Contractor’s Final Split (A+B+C)

Gas (48%) Additional Split

For Further Information, please contact:

Secretariat of Tender Committee/Evaluation Committee

Gedung Migas, 7

th

_Floor

Jl. H.R. Rasuna Said Kav.B-5, Jakarta 12910, Indonesia

Phone. +62-21 5268910 ext. 132, 135, 136, Fax +62-21-5268963

Unconventional PSC

 Coalbed Methane : 48 PSC

 Shale Gas : 6 PSC

INDONESIA UNCONVENTIONAL OIL & GAS RESOURCES AND PSC

WHY DEVELOP UNCONVENTIONAL OIL AND GAS IN INDONESIA ?

•

Demand for conventional oil and gas is increasing while its reserve

decreasing.

•

Unconventional Oil and Gas resources in Indonesia is very huge

•

G&G data is available from existing exploration activity that can be used

for Unconventional Oil & Gas Development

•

Infrastructure for Unconventional oil and gas development is sufficient

•

Domestic oil and gas price is competitive

•

Attractive Form of production sharing contract , split, handling before

production, and many other regulation that support contractors in

developing Unconventional oil & gas in Indonesia.

Indonesia Gas Reserves (Status January 2015)

PROVEN = 97,99 TSCF POTENTIAL = 53,34 TSCF TOTAL = 151,33 TSCF

REGULATIONS RELATED TO UNCONVENTIONAL OIL AND GAS

DEVELOPMENT IN INDONESIA

•

Undang

–

undang Republik Indonesia Nomor 22 Tahun 2001,

on oil and gas activities in Indonesia

•

Peraturan Pemerintah Republik Indonesia Nomor 35 Tahun

2004, on Indonesia Upstream Oil & Gas Business Peraturan

Menteri Energi dan Sumber Daya Mineral Nomor 36 Tahun

2008, on Coal Bed Methane Development

•

Peraturan Menteri Energi dan Sumber Daya Mineral Nomor 05

Tahun 2012, on Procedures of determining & bidding of

unconventional oil & gas working acreage

•

Peraturan Menteri Energi dan Sumber Daya Mineral Nomor 38

Tahun 2015, on Acceleration of Unconventional Oil & Gas

Development

•

Peraturan Menteri Energi dan Sumber Daya Mineral Nomor 8

SOME PRINCIPAL OF UNCONVENTIONAL OIL AND GAS

PSC TERMS AND CONDITIONS IN INDONESIA

•

Contractor provides all fund, technologies, necessities ability and risks

•

30 years contract on commercialities of unconventional oil and gas found

•

Exploration period is six (6) years, could be extended for final four (4) years

•

Contractor is obliged and required to relinquish the acreage (block) in phases

•

The split between government and contractor in production sharing (and in

kind) is more attractive than conventional

•

Contractor require to firmly commit for 3 years of exploration and suring

which contractor is not allowed to divest its majority shares in the acreage

•

Domestic market obligation for contractor

•

Signature bonus, equipment services, and production bonus

•

Available data package and speculative data

INDONESIA UNCONVENTIONAL OIL & GAS GROSS SPLIT PSC

Government

Contractor

(cost included)

Gross Production

(100%)

Base split before tax

Base Split :

Government

Contractor

Oil

57

43

Gas

52

48

Contractor Split

Base Split

Variable

Split

Progressive

Split

GEOLOGICAL SETTING

The Jambi Area is located within Jambi Sub-Basin part of South Sumatra Basin . The low of Jambi Area from north to south consist of Berembang Deep, Bajubang Deep, Kenali Asam Deep and partly Sungai Gelam Deep to the southern. The origin history of the South Sumatra Basin can be divided into three tectonic mega-sequence that is rift Megasequence, Post Rift Megasequence, and Syn-Orogenic /Inversion. Megasequence

SHALE HYDROCARBON SYSTEM

The reservoir properties are : average porosity (0.04); average water saturation (0.35);; average TOC 2.791%; Vitrinite Reflectance / Ro (> 0,6) and physical gas characteristic: volume factor of gas formation = 0.0029 cf/scf, volume factor of oil formation = 1,6 rb/stb, gas content = 119,25 scf/ton) and oil content = 0,027 stb/ton, Net To Gross = 0.01, and 0.02 for oil shale Estimation of calculated adsorbed gas is about 5.01 TCF and calculated freegas is about 8.30 TCF. Then total GIP in JSA is 13.31 TCF. Estimation of calculated oilshale is about 0.64 BBO

Sweetspot Oil Shale Sweetspot Gas Shale Residences

Area of interest

Area of interest is the distribution of Shale that is developed by

overlaid of depth structure and isopach maps, and then integrated

data analysis of maturity map from outcrop samples and well data;

but its need controlled by land use map for the best result.

Zone Gas type

Resource s (TCF)

P50 LAHAT Free Gas 1.15 Adsorb Gas 0.68 Total 1.83 Zone Resources (BBO) P50 TAF 0.07 LAHAT 0.15 Total 0.22 Zone Gas type

Resource s (TCF)

P50 TAF Free Gas 1.29 Adsorb Gas 0.89 LAHAT Free Gas 1.98 Adsorb Gas 1.16 Total 5.32

Zone Gas type

Resource s (TCF)

P50 LAHAT Free Gas 0.37 Adsorb Gas 0.22 Total 0.59 Zone Resources (BBO) P50 TAF 0.33 LAHAT 0.09 Total 0.42 Zone Gas type

Resource s (TCF)

P50 TAF Free Gas 0.11 Adsorb Gas 0.07 LAHAT Free Gas 3.40 Adsorb Gas 1.99 Total 5.57

Total Shale GAS WET AND DRY in TAF and Lahat Zone : 7.15 TCF Total Shale Oil in TAF and Lahat Zone : 0.22 BBO

Total Shale GAS WET AND DRY in TAF and Lahat Zone : 6.16 TCF Total Shale Oil in TAF and Lahat Zone : 0.42 BBO

RESOURCES SUMMARY WK MNK JAMBI I

Wet Gas Dry Gas Oil

For Further Information, please contact :

Secretariat of Offering Migas Investment Service Room Directorate General of Oil and Gas Ministry of Energy and Mineral Resources

Migas Building 1st_{Floor Jl. H.R. Rasuna Said Kav.B-5 Jakarta 12910}

Phone +62-21-5268910 ext.145 , Fax +62-21-5269151 E-wkmigas.esdm.go.id

MINISTRY OF ENERGY AND MINERAL RESOURCES DIRECTORATE GENERAL OF OIL AND GAS