Exploration Drilling in Indonesia in 2022

Drilling by Pertamina Hulu Energy at Offshore North West Java – Photo by Rick Patenaude

The year 2022 has been quite an active and eventful year for the oil and gas industry in Indonesia, especially in drilling.

Oil and gas operators drilled 760 development wells in 2022. This is slightly below its target of 790 wells, but it is a big increase from 480, the number of development wells drilled in 2021. We expect to see even higher drilling activities as the target of development drilling in 2023 is set at 991 wells.

In exploration drilling, oil and gas operators in Indonesia spudded 30 exploration wells in 2022 compared to 28 wells in 2021.

Out of the 27 exploration wells which were completed in 2022, 22 of them tested hydrocarbon resulting in an 81% success ratio in exploration drilling.

Here are the 22 exploration wells that tested hydrocarbon.

WELL NAMEOIL OR GASOPERATOR
Reentry TDE C-1X LSWGasPertamina Hulu Mahakam
MPT-1XGasPertamina Hulu Mahakam
Camelia – 001GasPertamina EP
Kenanga – 001GasPertamina EP
SGET – 001Oil and gasPertamina EP
SA S-1Oil and gasSele Raya Belida
GASOP D South – 1GasSele Raya Belida
JTB – 2X             GasPHE Ogan Komering
Flamboyan – 1XGasMedco
Timpan – 1GasHarbour Energy, Mubadala, BP
NSO – R2Oil and gasPHE – North Sumatra Offshore
NSO – S2GasPHE – North Sumatra Offshore
Anambas – 2XGasKUFPEC
Nuri – 1XOilBumi Siak Pusako (BSP)
SRT – 1XOil and gasPHE Jambi Merang
Wilela – 001GasPertamina EP
GQX – 1Oil and gasPHE – Offshore North West Java
Bajakah – 1Oil and gasPertamina EP
Kolibri – 001GasPertamina EP
Phoenix – 1XGasPertamina Hulu Sanga Sanga
Markisa – 001GasPertamina EP
Kembo – 001Oil and gasPertamina EP

Locations of the 22 discovery wells in 2022. Graphic provided by SKK Migas.

We expect to see a huge increase in exploration drilling in 2023 with a target of 57 wells as Indonesia is serious in its intention to meet its targets of producing 1 million barrels of oil per day and 12 billion SCF of gas per day by 2030.  

Here are synopses of oil and gas production, field development, and exploration activities in Indonesia in 2022, and what we can expect to see in 2023, according to SKK Migas.

This post is adapted by LDI Training from information provided by SKK Migas.

Jamin Djuang

Top Oil Producers in Indonesia in 2022

The total average daily oil and condensate production volume from all the oil producers in Indonesia in 2022 amounts to 612,712 barrels.

Here are the top 15 oil producers in Indonesia and their average daily oil and condensate production volume in barrels in 2022.

OIL OPERATORSAVERAGE BPD IN 2022
ExxonMobil Cepu Ltd165,906
Pertamina Hulu Rokan159,254
Pertamina EP70,157
Pertamina Hulu Energi ONWJ27,584
Pertamina Hulu Mahakam25,091
Pertamina Hulu Energi OSES19,638
PetroChina International Jabung Ltd15,610
Medco E&P Natuna10,255
Pertamina Hulu Sanga Sanga9374
Pertamina Hulu Kalimantan Timur9013
Bumi Sakti Pusako (BSP)8240
Saka indonesia Pangkah Ltd7624
JOB Pertamina Medco Tomori Sulawesi7839
Petronas Carigali Ketapang Ltd7579
Husky-CNOOC Madura Ltd6421
All others612,712

Oil and gas production in Indonesia in 2022 is lower than in the previous year, nevertheless, the year 2022 has been quite an active and eventful year for the oil and gas industry in Indonesia. We saw several new platforms were installed and an old platform was decommissioned, many development wells were drilled, and many idle wells were reactivated.

Here are synopses of oil and gas production, field development, and exploration activities in Indonesia in 2022, and what we can expect to see in 2023, according to SKK Migas.

Oil and Gas Activities in Indonesia in 2022

Timpan 1 Well – Discovery well of Harbour Energy, Mubadala, and BP at offshore Aceh. Photo courtesy of Peter Bruce

Oil and gas production in Indonesia in 2022 is lower than in the previous year, nevertheless, the year 2022 has been quite an active and eventful year for the oil and gas industry in Indonesia. We saw several new platforms were installed and an old platform was decommissioned. Many development wells were drilled, and many idle wells were reactivated.   

Here are synopses of oil and gas production, field development, and exploration activities in Indonesia in 2022, and what we can expect to see in 2023, according to SKK Migas.

Oil Production

The average daily oil production in 2022 is 612,300 BOPD. This is below its 2022 target and also below the actual oil production in 2021. The oil production target for 2023 is 660,000 BOPD.

The top three oil producers are ExxonMobil Cepu Ltd., Pertamina Hulu Rokan, and Pertamina EP. Here are the top 15 oil producers in Indonesia in 2022.

Gas Production

The daily gas production in 2022 is 5,347,000 MMSCFD. This is below its 2022 target and also below the actual gas production in 2021. The gas production target is 6,160,000 MMSCFD in 2023.

Development Wells

Operators drilled 760 development wells in 2022. This is slightly below its target of 790 wells. However, it is a big increase from the number of development wells drilled in 2021. The target of development drilling in 2023 is 991 wells.

Workovers and well services

Oil and gas operators carried out 639 well workovers and 30,299 well services in 2022.

Reactivation of Idle Wells

As one of the strategies to increase oil and gas production, 968 idle wells were reactivated in 2022. The target of idle wells that will be reactivated in 2023 is set at 1086.

Investment

Investment in oil and gas projects in 2022 amounted to 12.3 billion USD. This is below its 2022 target but is higher than the amount of investment in 2021. The target of investment in 2023 is 15.5 billion USD.

Reserves Replacement Ratio (RRR)

With 890 million barrels of oil equivalent of reserves added in 2022, the ratio of reserves replacement in 2022 reaches 156%. This is higher than the RRR of 116% achieved in 2021. The target RRR for 2023 is 100%. The two biggest new reserves came from the Hidayah field development and the rejuvenation of the Sanga Sanga field.

The Hidayah field is located in the North Madura II work area and is operated by Petronas Carigali. It has estimated oil reserves of 88 million barrels of oil.

Exploration Drilling

Oil and gas operators in Indonesia drilled 30 exploration wells in 2022. This is higher than the 28 exploration wells drilled in 2021. The target of exploration drilling is set at 57 wells for 2023.

Twenty-two out of the twenty-seven completed exploration wells tested hydrocarbon. This represents an 81% success rate in exploration drilling.

Here are the 22 exploration wells that tested hydrocarbon in 2022.

2D Seismic Surveys

Oil and gas operators carried out 1950 KM of 2D seismic survey in 2022. This is below its target and the actual survey done in 2021. The target of the 2D seismic survey for 2023 is set at 1087 KM.

3D Seismic Surveys

3790 KM2 of the 3D seismic survey was conducted in 2022. This is below its target but higher than the actual survey done in 2021. The target of the 3D seismic survey for 2023 is set at 4602 KM2.

Unconventional Oil and Gas

Another strategy to increase oil and gas production in Indonesia is to explore the potential of unconventional oil and gas resources. Pertamina plans to drill two unconventional wells in 2023 in the Rokan work areas.

Strategic Oil and Gas Projects

Here are updates on the status of the 4 national strategic oil and gas projects.

1.           Jambaran Tiung Biru – Gas production from the two unitized fields of Jambaran and Tiung Biru came on stream on 20 September 2022. It is considered a strategic project as it will supply gas to industries in Central Java and East Java.

2.           Tangguh LNG train #3 – Train #3 of the Tangguh LNG plant is expected to come on stream in the first quarter of 2023.

3.           The IDD project – The Indonesia deepwater development project is in the process of changing partnerships and operatorship. 

4.           The Abadi Masela project – Pertamina is in the process of acquiring the interest of Shell in the project. The project is expected to be completed in 2029. 

Epilogue

As Indonesia is serious in its ambition to increase its oil and gas production, SKK Migas has set higher exploration and production targets for 2023. Also, the government has said that it will ratify the current oil and gas regulations to give stronger legal certainty to oil and gas investors and to attract more investments in 2023 and beyond.

We shall see an even more active and eventful year in 2023.

This article is adapted from the announcement made by SKK Migas on 18 January 2023. – Jamin Djuang

Countries with the Largest Oil Reserves in 2021

Photo courtesy of Rick Patenaude

The latest total oil reserves in the world amount to 1757 billion barrels.

This amount can last for 55 years assuming the daily global oil consumption of 97 million barrels per day.

Here are the world’s top 20 countries having the largest oil reserves in billions of barrels in 2021.

  1. Venezuela – 303.8
  2. Saudi Arabia – 258.6
  3. Iran – 208.6
  4. Canada – 170.3
  5. Iraq – 145
  6. Russia – 108
  7. Kuwait – 101.5
  8. United Arab Emirates – 97.8
  9. Libya – 48.4
  10. USA – 47.1
  11. Nigeria – 36.9
  12. Kazakhstan – 30
  13. China – 26
  14. Qatar – 25.2
  15. Brazil – 12.7
  16. Algeria – 12.2
  17. Ecuador – 8.3
  18. Norway – 8.1
  19. Angola – 7.8
  20. Azerbaijan – 7

Pertamina Geothermal Energy – The Maverick

The Lumut Balai geothermal power plant of Pertamina Geothermal Energy.

Pertamina Geothermal Energy (PGE) is a big and very active geothermal energy player in Indonesia. It is the operator of the first geothermal power plant in Indonesia – The Kamojang plant.

Engaging in thirteen geothermal work areas in Indonesia, PGE involves in the production of 1877 MW of geothermal power, 672 MW of which is under its operation and 1205 MW under the joint operation contracts.

PGE operates six of its solely owned geothermal plants and has interests in four other geothermal plants that are under a joint-operating contract scheme.

Pertamina Geothermal Energy has targets to increase its own power generation capacity from 672 MW to 1540 MW by 2030 contributing to reducing 9 million tons of CO2 emission annually.

As PGE aims to be a world-class green energy producer and to accelerate its ambitious geothermal expansion, it plans to launch an initial public offering (IPO) in the first quarter of 2023. The IPO has the potential to raise 500 million USD of new equity capital for the company.

Here are its current projects:

• Constructing the Lumut Balai 55 MW Unit 2 power station. Pertamina Geothermal Energy has commissioned the Mitsubishi Power consortium to construct its second 55-MW power station in the Lumut Balai work area in South Sumatra. When completed, the Lumut Balai geothermal plant will have an installed capacity of 110 MW.

• Completing a small-scale 500 KW geothermal power plant in Lahendong. This will serve as a model for small geothermal power plants to be built in other parts of the country.

• Recently PGE signed an MOU with Ormat Technologies to conduct a joint study on developing power plants using binary technology. CEO of PGE, Ahmad Yuniarto said that the application of binary technology has the potential to increase its current already installed generation capacity by up to 210 MW.

• PGE is exploring a partnership with Chevron targeting the utilization of geothermal energy for other purposes including such as green hydrogen production, CO2 processing, and extraction of rare metals.

• Pertamina Geothermal Energy sets out to expand its Ulubelu geothermal power plant located in Lampung, Indonesia. It plans to drill six wells in 2023. Currently, the Ulubelu power plant consisting of four power stations have a combined installed capacity of 220 MW. Pertamina is the operator of two of the power units while PLN is the operator of the other two power units.

The six geothermal plants that PGE operates are:

  1. Kamojang in West Java – 235 MW
  2. Ulubelu in Lampung, South Sumatera – 220 MW
  3. Lahendong in North Sulawesi – 120 MW
  4. Lumut Balai Unit 1 in South Sumatera – 55 MW
  5. Karaha in West Java – 30 MW
  6. Sibayak in North Sumatera– 12 MW

The Expanding Tangguh LNG

The Tangguh LNG Train #3 is under construction. Photo courtesy of Moch. Ali Masyhar.

The Government of Indonesia has granted a 20-year extension of the Tangguh production sharing contract (Tangguh PSC). Under the agreement, the Tangguh PSC which is due to expire in 2035, has been extended to 2055.

The Tangguh PSC covers three work areas. They are Berau, Muturi, and Wiriagar.

The partners under the Tangguh PSC are BP as the operator, MI Berau B.V., CNOOC Muturi Ltd., Nippon Oil Exploration (Berau) Ltd., KG Berau Petroleum Ltd., KG Wiriagar Petroleum Ltd., and Indonesia Natural Gas Resources Muturi Inc.

The 20-year contract extension is expected to generate 5 billion USD in revenues for the government of Indonesia.

Anja-Isabel Dotzenrath, BP’s EVP of Gas & Low Carbon Energy, said: “This extension reflects BP’s long-term commitment to Indonesia. It will allow us to continue to build on the great work that our Indonesia team has been doing with our partners and the strong support of the Government to deliver much-needed natural gas safely and reliably from Tangguh to Indonesia, and other markets. Today’s agreement will help open new possibilities for Tangguh’s future.”

The prolific Tangguh is currently the largest gas-producing work area in Indonesia, accounting for around 20% of the country’s gas output. It has generated significant revenues for Indonesia, both at the national government level and in both Papua Barat province and Teluk Bintuni regency where the project is located.

To process the produced natural gas, the Tangguh LNG was constructed in 2009. The plant has safely delivered more than 1,450 cargoes of LNG to both local and international markets.

Its two LNG production trains have a combined liquefaction capacity of 7.6 million tons of LNG a year.

A third LNG train is currently under construction and is expected to come online in 2023, increasing Tangguh’s production capacity by 50%. 

BP and its partners are also working on the Tangguh UCC project, for which the Government of Indonesia approved a Plan of Development in 2021. The project comprises the development of the Ubadari gas field, enhanced gas recovery (EGR) through carbon capture, utilization, and storage (CCUS) in the Vorwata field, and onshore compression.

BP has vast interests in Indonesia. As the operator of the Tangguh project, BP also has interests in the Andaman II block offshore Aceh and has recently signed new PSCs for Agung I and Agung II blocks. 


Source: BP Press Release on 23 December 2022

CCS Projects Around the World

We are seeing growing interests on the application of the CCS technologies to reduce carbon emissions around the world. CCS (Carbon Capture and Storage) is one of the ways to achieve net zero emissions.

Although CCS technologies have been around for many years, so far, there are only a few industrial plants that are equipped with CCS facilities. However, this is set to change as companies, especially oil and gas companies, begin to have serious interest in undertaking CCS and CCUS.

CCUS goes beyond CCS by utilizing the captured CO2 to achieve other purposes such as enhancing the recovery of hydrocarbon from the reservoirs.

Here are a few CCS and CCUS projects that are in the pipeline or being planned around the world.

JAPAN

Aiming at reducing the carbon emissions, Japan’s Ministry of Economy, Trade and Industry (METI) initiated the Tomakomai CCS Demonstration Project in 2012.

For this project, Japan CCS was commissioned to construct a CCS demonstration test plant in Tomakomai, Hokkaido, drill several injection wells, and construct a monitoring system to observe the behavior of CO2 and subsurface conditions after CO2 injection.

In April 2016, Japan CCS commenced injection of CO2 into a formation about 1,000 meters below the seabed.  In November 2019, the CO2 injection reached the target of 300,000 tonnes.

Following the injection, the company started Monitoring work that includes confirming that there is no CO2 seepage through monitoring the behavior of the injected CO2, constant monitoring of micro-seismicity and natural earthquakes, and conducting marine environmental surveys.

MALAYSIA

Petronas Carigali took FID (final investment decision) to develop the 3.3-million tonne/year carbon capture and storage (CCS) project at 3.2 TCF Kasawari sour gas field in Block SK316 offshore Sarawak, Malaysia.

The project, about 200 km off Bintulu, will capture and process CO2 from the field for injection into a depleted gas field.

THE UK

Phillips 66 in the UK is developing what could become the first-ever industrial-scale carbon capture project executed within a refinery at its affiliate’s 221,000 b/d Humber plant, with front-end engineering and design work awarded to Worley Ltd. expected to be complete by the end-2023.

NEW ZEALAND

New Zealand Energy has requested that the New Zealand oil and gas regulator, New Zealand Petroleum and Minerals, amend petroleum mining licenses 38140 (Waihapa) and 38141 (Ngaere) to allow for carbon sequestration.

INDONESIA

ExxonMobil and Pertamina signed a Heads of Agreement to further progress their regional carbon capture and storage hub (CCS) for domestic and international CO2.

The agreement defines the next steps for the project offshore Java—where the companies estimate geologic storage potential of up to 3 billion metric tons—including concept-select, pre-front-end engineering design, and a subsurface work program.

PEMA (PT Pembangunan Aceh) recently formed a joint-venture company, PT Carbon Aceh, to repurpose the now-depleted giant Arun field gas reservoir offering open-access storage of CO2 in 2029.

BP Indonesia has opened a pre-qualification tender for the provision of onshore front-end engineering and design (FEED) services for a carbon capture and storage (CCS) project at its Tangguh liquefied natural gas (LNG) complex in Indonesia.

BP and its Tangguh LNG partners today confirmed that Indonesian oil and gas regulator SKK Migas has approved the plan of development (POD) for a key carbon capture utilization and storage (CCUS) project at the Tangguh LNG export complex.

BP said this CCUS project will make Tangguh one of the lowest greenhouse gasses (GHG) intensity LNG plants in the world.

The scope of the Tangguh CCUS project includes the utilization of the separated CO2. The CO2 separated from the incoming natural gas will be reinjected back to the Vorwata gas reservoir for sequestration and enhanced gas recovery. The total emissions reduction is up to 25 million tonnes of CO2 equivalent by 2035.

AUSTRALIA

British Petroleum has entered into a non-binding agreement with Santos that will lead to BP investing in Santos’ Moomba carbon capture and storage (CCS) project in South Australia.

The carbon dioxide that is separated from natural gas will be captured at the Moomba gas processing plant and reinjected into the geological formations of the Cooper Basin. This will aim to capture 1.7 million tonnes of carbon dioxide each year.

The Cooper Basin’s reinjection capacity has been assessed at up to 20 million tonnes of carbon dioxide per year, for 50 years. This has the potential to be a large-scale carbon sink for power generators and other industries in Australia.

SINGAPORE

Chevron through its Chevron New Energies International subsidiary, and Mitsui O.S.K. Lines (MOL) will explore the technical and commercial feasibility of transporting liquified CO2 from Singapore to permanent storage sites offshore Australia.

“Developing safe and reliable CO2 transportation services is a crucial step in developing large-scale Carbon Capture, Utilization, and Storage (CCUS) solutions, said Mark Ross, president of Chevron Shipping Co.

THE US

BP and Linde recently announced plans to advance a major carbon capture and storage (CCS) project in Texas that will enable low-carbon hydrogen production at Linde’s existing facilities. The development will also support the storage of carbon dioxide (CO2) captured from other industrial facilities – paving the way for large-scale decarbonization of the Texas Gulf Coast industrial corridor.

Upon completion, the project will capture and store CO2 from Linde’s hydrogen production facilities in the greater Houston area – and potentially from its other Texas facilities – to produce low-carbon hydrogen for the region. The low-carbon hydrogen will be sold to customers along Linde’s hydrogen pipeline network under long-term contracts to enable the production of low-carbon chemicals and fuels.

This article is adapted by LDI Training from various sources.

The Super Giant Arun Gas Field

The monument showing the location of the first well of the Arun gas field.

About The Unique Arun Gas Field

The Arun field is a supergiant gas field. It had 16 trillion cubic feet of original gas in place and was discovered in 1971 by Mobil Oil in Aceh, Sumatra.

Interestingly, the gas concession was initially held by Asamera. Due to unsuccessful exploration by Asamera, it was sold to Mobil Oil in 1968.

The Arun gas reservoir had abnormally high temperatures and pressure of 178 degrees C and 7100 PSIG respectively. The reservoir is made up of carbonate rock located at 10,000 feet in depth.

Due to its high pressure, porosity, permeability, and reservoir thickness of about 500 feet, the Arun gas wells were extremely productive. Each well could produce more than 100 MMSCF of gas per day.

The highly prolific Arun field produced over 3000 MMSCF of gas per day from its 78 wells for more than 10 years. The produced natural gas was fed into the Arun LNG plant to recover the condensate and liquefy the gas.

The field is estimated to have produced over 14 trillion cubic feet of natural gas and 840 million barrels of condensate.

As a retrograde gas reservoir with no water drive, Mobil Oil took extreme care to manage the reservoir to achieve the highest gas recovery possible. Steps, such as gas reinjection, were taken to manage the reservoir pressure. Up to 900 MMSCF of dry gas were injected back into the reservoir daily through 11 injection wells.

As the reservoir and wellhead pressures eventually declined, gas compressors were used to boost gas production.   

By 2014, the Arun field gas production had become so low that the LNG plant was shut down permanently.

The now depleted and low-pressure Arun gas reservoir is a great candidate for storing captured CO2 as it is a volumetric reservoir meaning the reservoir is completely sealed. It is enclosed by impermeable barriers that prevent any fluid from entering or leaving the reservoir.

The Arun LNG Plant

The Arun LNG plant was built to monetize the huge amount of the discovered gas. It is the first LNG plant built in Indonesia and Southeast Asia.

Initially, the Arun LNG plant consisted of three LNG trains that started to operate in August 1978, September 1978, and February 1979 respectively.

Two trains were later added to the plant in October 1983 and January 1984 respectively.

All five trains produced a total of 55,000 M3 per day of LNG and 115,000 barrels per day of condensate.

The LNG plant eventually had six trains. The sixth train was completed in November 1984.

Up till 1999, Indonesia produced one-third of the LNG in the world.

A major problem in processing Arun gas is that the gas has a large percentage of mercury and it reacts with aluminium in the cryogenic system to form an amalgam.

After 36 years in operation, the Arun LNG plant was finally shut down in 2014.

The Gas Well Blowouts

The massive blowout in the Arun field happened in 1978 when the CII-2 well in the Arun field was being drilled.

The blowout killing efforts were led by Red Adair. Initially, the well control team attempted to kill the well from the top.  However, it failed.

Finally, the blowout was killed by drilling a directional well and then pumping a huge amount of acid followed by heavy mud into the bottom of the CII-2 well.

The blowout was so huge and due to the extremely high reservoir pressure, more than fifty high-pressure and high-volume mud pumps, and more than one hundred pump operators and engineers were brought in from several countries to kill the blowout.

Another Arun well, CIII-8, blew out two years later in 1980.

The Ambitious Arun CCS Project

Although the huge Arun field reservoir has been almost completely depleted for some time, it may have a second life.

As the world is committed to reducing carbon emissions by capturing emitted CO2, the Arun field has a huge potential to become the largest storage facility for captured carbon in Asia.  

PEMA (Pembangunan Aceh) has formed a joint venture company, Carbon Aceh, to perform a feasibility study up to the development, implementation, and operation of the Arun CCS project which is planned to start operating in 2029.

The depleted Arun gas reservoir is a perfect candidate for storing CO2 for the following reasons:

  • It is almost completely depleted and therefore it has low pressure.
  • It is completely enclosed and therefore the storage space is completely sealed.
  • It has an enormous volume of storage space. It can store more than 1 billion metric tonnes of CO2.

Moreover, the Arun field already has infrastructure that can be used to facilitate the CCS project such as offshore terminals that can receive CO2 shipments from CO2 tankers and pipelines that can transport the CO2 to the Arun field.

Marzuki Daham, former Chairman of BPMA – Aceh Oil & Gas Regulatory Body – gave his comment on this important CCS project.

“A great location with the existing infrastructure will surely be a plus to support the project. It would be even more interesting if Arun can be an open-access storage for captured CO2 from many countries around the area. It is a step to save the planet.”

When the Arun carbon storage facility becomes operational, the Arun field will be known not just as one of the largest gas fields and LNG plants in the world, but it will also be known as one of the largest carbon storage facilities in the world.

This article is adapted from various sources by Jamin Djuang – Chief Learning Officer of LDI Training and author of “The Story of Oil and Gas – How Oil and Gas are Explored, Drilled and Produced”.

Oil and Gas Activities in Indonesia in Third Quarter 2022


The oil and gas industry of Indonesia has been active and alive in the first nine months of 2022, and it expects to up the tempo of its exploration and production activities as it marches toward the year-end.

Here is the summary of oil and gas activities in Indonesia at the end of the third quarter of 2022 according to a report published by SKK Migas.

DEVELOPMENT WELL DRILLING

Oil and gas operators in Indonesia drilled 545 development wells in the first three quarters of 2022.

The head of SKK Migas, Mr. Dwi Soetjipto, said that the number of development wells drilled by the end of the third quarter of 2022 has exceeded the number of wells drilled in 2021.

To meet the daily oil and gas production targets, it has increased the target of the number of development wells in 2022 from 790 to 801.

EXPLORATION DRILLING

Oil and gas operators drilled 21 exploration wells in the first three quarters. This is the same number of exploration wells drilled in the same period in 2021.

WELL INTERVENTION

Oil operators carried out 495 workovers in the first three quarters. This number is 87% of the 2022 workover target.

At the same time, well service operations also took place at a high tempo. Companies carried out more than 22000 well service operations. This number represents 99% of the 2022 target.

OIL AND GAS PRODUCTION

Here is the daily oil and gas production at the end of September 2022.
Oil – 613,000 BOPD
Gas – 5,353,000 MMSCFD

The combined daily oil and gas production is 1,562,000 BOEPD. This number is around 90% of the 2022 target.

As most of the oil and gas fields are very old, while operators are drilling wells to increase production, they also are experiencing high rates of natural decline.

STATE REVENUES FROM OIL AND GAS

The oil industry contributed USD 13.95 billion or IDR 202 trillion to the coffers of the government of Indonesia in the first nine months of 2022.

In just 9 months, this amount has exceeded the entire 2022 target of the state revenues from oil and gas by 40% due to the high prices of oil.

RESERVE REPLACEMENT

The oil and gas reserve replacement ratio (RRR) reaches 97.5% of the 2022 target.

SKK Migas expects the RRR will reach 186% of the 2022 target by the end of this year as several plan of development (POD) will be approved.

The RRR realized in the past five years has been greater than 100% of the target.

MULTIPLIER EFFECTS OF OIL AND GAS OPERATIONS

The oil and gas industry activities create positive and significant multiplier effects to the economy of Indonesia besides generating substantial revenues to the government.

The value of the components produced domestically in oil equipment and services sold amounts to USD 2.9 billion or IDR 42 trillion.

TKDN (Tingkat Komponen Dalam Negeri), the percentage of domestic components or services in products, reaches nearly 64%.

SKK Migas is actively encouraging and promoting national entrepreneurs and equipment manufacturers to meet the needs of the oil and gas industry.

ONE-DOOR SERVICE POLICY

The One Door Service Policy (ODSP) of SKK Migas has been very instrumental in getting permits and licenses approved quickly.

The average licensing process period has been sharply reduced to about 1 day from 14 days before the ODSP policy was introduced.

SKK Migas is committed to making it easy for oil operators to carry out their exploration and production activities as it continues to encourage massive and aggressive efforts by oil operators to increase their oil and gas production.


This article is adapted by Jamin Djuang from a recent article published by SKK Migas – The Special Task Force for Upstream Oil and Gas Business Activities of Indonesia.

Top Oil and Gas Operators in Indonesia in 2022

Production and drilling operations at the Bekapai field of Pertamina Hulu Mahakam

Here are the fifteen oil and gas operators in Indonesia with significant production volume and the potential to increase them, according to SKK Migas.

  • BP Berau
  • Eni East Sepinggan
  • Exxon Mobil Cepu 
  • Husky-CNOOC Madura
  • Medco E&P Grissik
  • PetroChina International Jabung
  • Premier Oil Natuna Sea B.V.
  • Pertamina EP
  • Pertamina Hulu Energi Jambi Merang
  • Pertamina Hulu Energi ONWJ
  • Pertamina Hulu Energi OSES
  • Pertamina Hulu Kalimantan Timur
  • Pertamina Hulu Mahakam
  • Pertamina Hulu Rokan 
  • Pertamina Hulu Sanga Sanga

This post is adapted by LDI Training from information posted by SKK Migas, the oil and gas regulator of Indonesia.

The Humongous Well Blowout of Arun Field

The biggest gas well blowout in Indonesia happened in 1978 when the CII-2 well in the Arun field was being drilled. This blowout is also the biggest in Southeast Asia ever.

About The Super Giant Arun Gas Field

The Arun field is a supergiant gas field. It had 16 trillion cubic feet of original gas in place and was discovered in 1971 by Mobil Oil in Aceh, Sumatra.

The Arun gas reservoir had abnormally high temperatures and pressure of 178 degrees C and 7100 PSIG respectively. The reservoir is made up of carbonate rock located at 10,000 feet in depth.

Due to its high pressure, porosity, permeability, and reservoir thickness of about 500 feet, the Arun gas wells were extremely productive. Each well could produce more than 100 MMSCF of gas per day.

The highly productive Arun field produced over 3000 MMSCF of gas per day for more than 10 years. The produced natural gas was fed into the Arun LNG plant to recover the condensate and liquefy the gas.

The field is estimated to have produced over 14 trillion cubic feet of natural gas and 840 million barrels of condensate.

As a retrograde gas reservoir with no water drive, Mobil Oil took extreme care to manage the reservoir to achieve the highest gas recovery possible. Steps, such as gas reinjection, were taken to manage the reservoir pressure. As the reservoir and wellhead pressures eventually declined, gas compressors were used to boost gas production.   

The now-depleted Arun reservoir is a great candidate for storing captured CO2 as it has no water influx and is at low pressure.

The Arun LNG Plant

The Arun LNG plant was built to monetize the huge amount of the discovered gas. It is the first LNG plant built in Indonesia and Southeast Asia.

Initially, the Arun LNG plant consisted of three LNG trains that started to operate in August 1978, September 1978, and February 1979 respectively.

Two trains were later added to the plant in October 1983 and January 1984 respectively.

All five trains produced a total of 55,000 M3 per day of LNG and 115,000 barrels per day of condensate.

The LNG plant eventually had six trains. The sixth train was completed in November 1984.

Up till 1999, Indonesia produced one-third of the LNG in the world.

A major problem in processing Arun gas is that the gas has a large percentage of mercury reacts with aluminium in the cryogenic system to form an amalgam.

After 36 years in operation, the Arun LNG plant was finally shut down in 2014.

The Gas Well Blowout

The massive blowout in the Arun field happened in 1978 when the CII-2 well in the Arun field was being drilled.

The blowout killing efforts were led by Red Adair. Initially, the well control team attempted to kill the well from the top.  However, it failed.

Finally, the blowout was killed by drilling a directional well and then pumping a huge amount of acid followed by heavy mud into the bottom of the CII-2 well.

The blowout was so huge and due to the extremely high reservoir pressure, more than fifty high-pressure and high-volume pumps, and one hundred pump operators and engineers were brought in from several countries to kill it.

The photo above, courtesy of Pete Hackney, showed another Arun well, CIII-8, that blew out two years later in 1980. You can see the rig drilling a directional well that would intersect the blowing-out well to kill it.

Oil and Gas Activities in Indonesia in May – June 2022

A pumping well of Pertamina. Photo courtesy of Pertamina

Here is the monthly summary of oil and gas exploration and production activities in Indonesia in May 2022, according to SKK Migas.

·     Daily crude oil production: 616,800 BOPD
·     Daily gas production: 5321 MMSCFD
·     Daily oil and gas production: 1,567,000 BOEPD
·     Exploration wells drilled YTD: 11
·     Development wells drilled YTD: 291
·     2-D seismic survey completed YTD: 559 KM
·     3-D seismic survey completed YTD: 269 KM2
·     Amount of investment YTD: USD 3.9 billion
·     Number of Work Areas: 170

Here are other recent happenings in the oil patch of Indonesia.

·     Pertamina recorded $2.046 billion corporate profit in 2021. This almost doubles the profit it made in 2020. 
·     Pertamina EP has completed the construction of the Beringin A gathering station in Muara Enim in South Sumatera. The gathering station is designed to increase the capacity of the Prabumulih field to handle an additional 15 million MMSCFD of gas and 382 BPD of condensate.  
·     Pertamina Hulu Energy has made hydrocarbon discovery from its exploration well GQX-1 in the Offshore North West Java (ONWJ) work area.
·     Gas production from the newly completed JML1 platform in the Jumelai field operated by Pertamina Hulu Mahakam had come on stream. The gas is piped to the production facility of the Senipah-Peciko-South Mahakam field. The Jumelai project is expected to produce 45 MMSCFD of gas and 710 BPD of condensate.
·     PT BSP (Bumi Siak Pusako) has started drilling its exploration well Nuri-1X in the CPP (Corridor Plain and Pekanbaru) Block in Riau. The company plans to drill 15 development wells and two exploration wells in 2022.
·     Pertamina Hulu Energy has started drilling the exploration well NSO-R2 in the North Sumatera Offshore work area.
·     Gas production from the new platform WPS-3 of Pertamina Hulu Mahakam came on stream on 10 June 2022. The installation of the WPS-3 platform and the subsequent drilling of the development wells are part of the JSN (Jumelai, North Sisi, and North Nubi) project. This platform is designed to handle 45 MMSCFD of gas.

This article is curated by Jamin Djuang, Chief Learning Officer of LDI Training.

High Potential Individuals

Stanford University Campus – Photo courtesy of Pexels – Zetong Li

Do you want to be a “high potential individual”? The secret lies in having a good education.

Education is a great social equalizer. A good education can level the playing field for everyone, especially disadvantaged people. Education can open more and better opportunities for them in the future and provide the chance for them to work and live in the places of their dream.

Indeed, the UK government has just announced it is inviting “high potential individuals” to apply to work and live in the UK.

You are considered a “high potential individual” by the UK Government if you are a recent graduate from the world’s top 37 universities outside of the UK. These are universities outside the UK that appeared at least twice in the Top 50 rankings in 2021.

So, you are a “high potential individual” if you are a recent graduate from the following 37 universities located outside the UK:

  • California Institute of Technology (Caltech) — U.S.
  • Chinese University of Hong Kong (CUHK) — Hong Kong
  • Columbia University — U.S.
  • Cornell University — U.S.
  • Duke University — U.S.
  • Ecole Polytechnique Fédérale de Lausanne (EPFL Switzerland) — Switzerland
  • ETH Zurich (Swiss Federal Institute of Technology) — Switzerland
  • Harvard University — U.S.
  • Johns Hopkins University — U.S.
  • Karolinska Institute — Sweden
  • Kyoto University — Japan
  • Massachusetts Institute of Technology (MIT) — U.S.
  • McGill University — Canada
  • Nanyang Technological University (NTU) — Singapore
  • National University of Singapore — Singapore
  • New York University (NYU) — U.S.
  • Northwestern University — USA
  • Paris Sciences et Lettres – PSL Research University — France
  • Peking University — China
  • Princeton University —  U.S.
  • Stanford University — U.S.
  • Tsinghua University — China
  • University of British Columbia — Canada
  • University of California, Berkeley — U.S.
  • The University of California, Los Angeles (UCLA) — U.S.
  • University of California, San Diego — U.S.
  • University of Chicago US — U.S.
  • University of Hong Kong — Hong Kong
  • University of Melbourne — Australia
  • University of Michigan-Ann Arbor — U.S.
  • University of Munich (LMU Munich) — Germany
  • University of Pennsylvania — U.S.
  • The University of Texas at Austin —  U.S.
  • University of Tokyo — Japan
  • University of Toronto — Canada
  • University of Washington — U.S.
  • Yale University — U.S.

Now we know why everyone wants to go to the best universities in the world.

The Bekapai – From an oil field to a gas field

The Bekapai field underwent Phase 2B Expansion. Photo from Pertamina.

THE DISCOVERY

In 2022, the Bekapai oil field, located offshore of the Mahakam Delta in East Kalimantan in Indonesia, celebrates its 50th anniversary.

The Bekapai field was discovered in April 1972 by Total along with its partner, Japex.

The field was almost undiscovered had Total’s exploration team given up its exploration drilling campaign after drilling six dry wells.

With the discovery of the Bekapai field, Total Indonesie went on to discover many big oil and gas fields in the Mahakam block – Tunu, Sisi-Nubi, Tambora, Handil, and Peciko.

Although the Bekapai is not as big as the other fields in the Mahakam block, the Bekapai field is the most well-known field in the Mahakam block being the first oil field that was discovered by Total Indonesie in East Kalimantan. A nice park in Balikpapan is named after Bekapai – Bekapai Park.

FIELD DEVELOPMENT AND PRODUCTION

The reservoirs of the Bekapai field are described as complex multi-layered reservoirs.

Total Indonesie constructed ten platforms and drilled 74 development wells between 1974 and 1996.

The Bekapai field began as an oil field. Oil production started in 1974 with peak production at around 60,000 BOPD in 1978. Then its oil production declined slowly until it reached around 1,000 BOPD in 2007.

As its oil production reached its lowest level, to rejuvenate its oil and gas production the field underwent several redevelopment and transformation projects.

FIELD EXPANSION AND TRANSFORMATION

Phase 1 Expansion

Total Indonesie initiated the Phase 1 field expansion project in 2008. The company drilled 9 development wells and production increased to 10,000 BOPD and 46 MMSCFD of gas by 2013.

With the success achieved in Phase 1 Expansion, the company conducted a 3D seismic survey to assess the potential of the Bekapai field for further development.

Phase 2A Expansion

Based on the encouraging seismic results, the company embarked on the Phase 2A expansion project to further develop the Bekapai Field.

The company drilled two development wells in 2014 and its oil production increased to 11,500 BOPD. This is a record oil production rate of the Bekapai field in its first 25 years of production.

Phase 2B Expansion

As the oil reserves of the Bekapai are depleted, Total’s engineers turn their attention to producing its gas.

The objective of Phase 2B Expansion is to produce the so-far untapped gas accumulation in the Bekapai reservoirs. The plan is to increase the capacity of the field to produce 100 MMSCFD of gas.

Here were what was involved in the Phase 2B Expansion Project.

  • Produced the gas remaining in the gas caps.
  • Increased the capacity of the offshore production facilities to produce 100 MMSCFD of gas.
  • Platform modifications
  • Constructing a 12,6 km long submarine 12-inch pipeline from the Bekapai field to the Peciko field.

Phase 2B Expansion transformed the Bekapai field from an oil field to a gas field. The project increased the gas production of the Bekapai field from around 40 MMSCFD to 92 MMSCFD in 2015, making it a significant gas contributor to LNG production.

Phase 3 Expansion

Pertamina Hulu Mahakam as the new operator continues to further tap the gas potentials of the Bekapai field under the Phase 3 Expansion.

This ongoing expansion project involves modifying the manifold wellhead platforms BH and BE to accommodate 5 new development wells.

This project is expected to produce an additional 27 MMSCFD of gas when it is completed in November 2022.

POSTLUDE

On January 2, 2018, Pertamina Hulu Mahakam became the operator of the Bekapai field and all the fields in the Mahakam block.

Pertamina Hulu Mahakam maintains the spirit of innovation and continues to develop the remaining potential of the 50-year-old oil field.

Pertamina Hulu Mahakam managed to reach ten years without LTI (Lost Time Injury) on August 27, 2021.

And finally, with the saying “An old oil field never dies”, may the Bekapai field continues to find a new life.

The First Geothermal Plants Around The World

The Matsukawa Geothermal Power Plant – The first geothermal power plant in Japan. Photo courtesy of Dr. Roland N. Horne

The utilization of geothermal resources to produce electricity has been increasing since the invention of the first geothermal energy generator by Piero Ginori Conti in Italy in 1904.

By 2021, there are more than one hundred geothermal power plants located around the world producing electricity with a total installed capacity of 15854 MW.

Want to know when and where the first geothermal power plants were set up around the world?

Here are the first geothermal power plants built in significant geothermal energy-producing countries.

THE LARDERELLO PLANT – ITALY – 1913

The first and the oldest geothermal power plant in the world is in Larderello in Italy.

Following the invention of the first geothermal energy generator by Piero Ginori Conti in 1904, the Larderello 1 geothermal power plant was completed in 1913 with a capacity of 250 kW.

The Larderello area now has 34 geothermal power plants having a total capacity of 800 MW.

By the way, the Larderello steam field is so awesome that it is referred to as Valle del Diavolo – Devil’s Valley.

Today, Italy has a total installed capacity of 944 MW making it the seventh-largest geothermal energy producer in the world.

WAIRAKEI PLANT – NEW ZEALAND – 1958

New Zealand is the second country in the world that built a geothermal power plant.

The first geothermal plant in New Zealand, the Wairakei Unit 1 station was completed in 1958 with a capacity of 11.2 MW. The Wairakei geothermal plant is located at North Taupo.

Today, the Wairakei geothermal power plant has a total combined capacity of 330 MW provided by Wairakei power stations 1 to 16, Te Mihi power stations 1 and 2 and Poihipi power station.

The number of geothermal power plants in New Zealand has grown to 15 producing 1037 MW of electricity making it the fifth-largest geothermal producing country in the world.

THE GEYSERS UNIT 1 PLANT – USA – 1960

The first geothermal power plant in the US is located at the Geysers. The Unit 1 plant was completed in 1960 with a capacity of 11 MW.

The Geysers geothermal field in California is the most prolific geothermal producing field in the US also in the world. It now has 18 geothermal power plants and a total installed capacity of 1590 MW.

Today the US with more than 69 geothermal power plants located in various states has a total installed capacity of 3722 MW. This makes the US the biggest geothermal energy producer in the world.

MATSUKAWA PLANT – JAPAN – 1966

The first geothermal power generation plant in Japan is the Matsukawa Geothermal Power Plant (Matsukawa Jinetsu Hatsudensho).

The plant started operating in 1966 with an initial capacity of 9.5 MW. It now has an installed capacity of 23.5 MW.

Today, Japan has more than 20 geothermal power plants operating in 18 locations producing 603 MW of electricity making it the tenth-largest geothermal energy producer in the world.

BJARNARFLAG PLANT – ICELAND – 1966

Bjarnarflag geothermal station is the oldest geothermal power plant in Iceland. Bjarnarflag was completed in 1966 having a capacity of 3 MW.

Following the success of the Bjarnarflag plant, several other power plants were built in Iceland.

Iceland, the land of ice and fire, is a natural place to tap its geothermal resources for energy. The country today produces 754 MW of electricity from its geothermal resources making it the ninth-largest geothermal producer in the world.

As 99.96% of its energy needs come from renewable resources, it is probably the greenest country in the world.

CERRO PRIETO PLANT – MEXICO – 1973

The first geothermal power plant in Mexico, Cerro Prieto 1 was commissioned in April 1973.

The Cerro Prieto field is the world’s largest known water-dominated geothermal field. It has five power stations with a total installed capacity of 820 MW.

Today, Mexico, generating 963 MW of electricity is the sixth-largest geothermal energy producer in the world.

KIZILDERE PLANT – TURKEY – 1974

The first geothermal power plant in Turkey is in Kizildere.

The Kizildere geothermal power plant began its operation in 1974 as a prototype system with a 500 KW capacity.

Ten years later, the Kızıldere Jeotermal Elektrik Santralı plant was commissioned in 1984 with an installed capacity of 17.4 MW.

In 2013, the Kizildere Geothermal Power Plant reached an installed capacity of 95 MW making it Turkey’s biggest.

Today, with a total of 1710 MW capacity, Turkey is the fourth largest geothermal energy producer in the world.

AHUACHAPAN PLANT – EL SALVADOR – 1975

The first geothermal power plant in El Salvador is located in Ahuachapan. It was built in 1975 with a capacity of 95 MW.

The second geothermal plant in El Salvador, the Berlin Power Plant, was later built with an installed capacity of 109 MW.

Currently, with a total capacity of 204 MW, geothermal energy generates 20% of the total energy needs in El Salvador.

The contribution of electricity from geothermal resources is set to increase in the future and two new geothermal power plants are scheduled to come online in 2023 and 2026 in the San Vicente and Chinameca fields.

LEYTE PLANT – THE PHILLIPPINES – 1977

The first geothermal power plant in the Philippines, the Leyte Geothermal Power Plant began operation in 1977.

Located on the island of Leyte, the plant started as a pilot plant using a portable 3 MW power generation unit connected to a wellhead.

With the success of the pilot plant, Leyte island now has five geothermal power plants.

Other geothermal plants in the Philippines are in the islands of Luzon, Mindanao, and Negros.

Today the Philippines with a total installed capacity of 1918 MW is the third largest geothermal energy producer in the world. 

OLKARIA I POWER STATION – KENYA – 1981

Olkaria I Geothermal Power Station is the first geothermal power plant in Kenya and Africa. The first unit having a capacity of 15 MW was commissioned in 1981.

Several units were added to the Olkaria I facility in later years bringing its total installed capacity to 185 MW by 1985.

Today Kenya has a total installed capacity of 861 MW making it the eighth largest geothermal energy producer in the world.

KAMOJANG PLANT – INDONESIA – 1982

Operating since 1982, the 235 MW Kamojang geothermal plant is the first geothermal power plant in Indonesia. It is located in the Garut area in West Java.

The Kamojang geothermal reservoir was first discovered by the Dutch more than one hundred years ago when it successfully drilled the first steam-producing well in Indonesia.

Today Indonesia has a total installed capacity of 2276 MW making it the second-largest geothermal energy producer in the world.

MOMOTOMBO PLANT – NICARAGUA – 1983

The Momotombo plant is the first geothermal power plant in Nicaragua.

Its first power generating unit of 35 MW was completed in 1983. A second 35 MW unit was later added in 1989 bringing the total capacity to 70 MW.

Nicaragua’s second geothermal plant is the San Jacinto Tizate which was completed in 2013 with an installed capacity of 72 MW.

MIRAVALLES PLANT – COSTA RICA – 1994

The first geothermal power plant in Costa is the 55 MW Miravalles plant commissioned in 1994.

Today with a total installed capacity of 207 MW, Costa Rica is the twelfth largest geothermal producer in the world.

ORTITLAN PLANT – GUATEMALA – 1998

The first geothermal power generation unit in Guatemala was built in Amatitlán geothermal area in 1998. It started as a portable power plant of 5 MW.

A full-scale 20 MW geothermal power plant, the Ortitlan, was later built in the Amatitlan area in 2008.

Guatemala’s second geothermal plant, the Orzunil, located in the Zunil geothermal area was completed with a capacity of 24 MW in 2001.

CERRO PABELLON PLANT – CHILE – 2017

The first geothermal power plant in Chile was built in 2017 by Geotermica del Norte (GDN), a joint venture between Enel Green Power Chile and ENAP.

Located at 4500 meters above sea level, the Cerro Pabellón is the highest geothermal plant in South America. It is located on the high plateau of the Atacama Desert in the Antofagasta Region of Chile.

The plant, which uses high enthalpy technology with a binary cycle, is the only operational geothermal plant in South America.

Its third power station with a capacity of 33 MW was completed in 2021 giving Cerro Pabellon a total power of 81 MW.

PLATANARES PLANT – HONDURAS – 2018

The first geothermal power plant of Honduras, the 35 MW Platanares geothermal plant was inaugurated in 2018.

CASANARE PLANT – COLOMBIA – 2021

Colombia inaugurated its first geothermal power unit located in Casanare in March 2021.

The first of its kind, this innovative 100 KW power unit takes advantage of the hot water produced along with the oil from the Las Maracas field.

YANGBAJAIN PLANT – TIBET – 1977

Yangbajain is the first geothermal power plant in Tibet, China. The plant was initially completed in 1977. It now has an installed capacity of 24 MW.

The Yangbajain plant is located at an elevation of 4800 meters above sea level making it the highest geothermal plant in the world.

EPILOGUE

The world is endowed with huge geothermal resources. As the world marches toward net zero-emission, we shall see the application of geothermal energy as a renewable resource to generate the electricity we need will continue to expand.

Indonesia inaugurated two geothermal plants in 2021: the 45 MW Unit II Sorik Marapi Geothermal Power Plant on 28 July 2021 and the 98.4 MW Rantau Dedap Power plant on 26 December 2021.

This article is written by Jamin Djuang – Chief Learning Officer of LDI Training – based on information from various sources.

As information, Dr. Roland N. Horne will teach Geothermal Reservoir Engineering, a virtual course, on December 12-15, 2022.

Top Geothermal Plants in Indonesia

Geothermal wells at Muara Laboh

Indonesia is the second-largest geothermal energy producer in the world after the USA. The total installed power generating capacity from the active 16 geothermal power plants in Indonesia is 2356 MW as of December 2022.

Indonesia is the biggest contributor to the increase of installed geothermal power in the world in 2021.

Indonesia added a total of 133 MW of capacity in 2021: 45 MW from Unit II Sorik Marapi Geothermal Power Plant on 28 July 2021 and 98.4 MW from the Rantau Dedap Power plant on 26 December 2021.

The country added a total of 80 MW of geothermal power in in 2022.

Located right on the long stretch of the ring of fire, Indonesian islands are endowed with rich geothermal resources. The total potential geothermal resources of Indonesia are estimated at 28,000 MW.

Although the geothermal potential is huge, its utilization rate is under 8%.

Here are the top ten largest geothermal plants in Indonesia in 2022.

The Kamojang Geothermal Plant

Operating since 1982, the 235 MW Kamojang plant is the first geothermal power plant in Indonesia. Located in the Garut area in West Java, it has been operating for 38 years.

The Dutch spotted the Kamojang geothermal potential more than one hundred years ago and drilled several wells in the area. In 1926 it successfully drilled the first steam-producing well in Kamojang, also the first in Indonesia.  

Later in I971, Pertamina Geothermal Energy (PGE) with cooperation from New Zealand began to develop the field followed by the construction of the Kamojang power plant, the first geothermal power plant in Indonesia.

The plant is operated by Pertamina Geothermal Energi.

The Salak Geothermal Power Plant

Producing 377 MW of power, the Salak plant is the largest geothermal power plant in Indonesia and is also one of the largest in the world.

Located at Gunung Salak in West Java, the Salak plant has been operating since 1994.

The Salak geothermal resources were initially explored and developed by Unocal. In 2005, the Salak geothermal assets were taken over by Chevron who eventually sold it to Star Energy in 2017. 

The Darajat Geothermal Plant

The 270 MW Darajat geothermal plant, located at Garut in West Java, started its commercial operation in 1994 and is one of the oldest geothermal power plants in Indonesia.

The Darajat geothermal assets were initially explored and developed by Amoseas. The assets were later taken over by Chevron who eventually sold it to a consortium led by Star Energy in 2017.

The Darajat resource has two special characteristics. First, it is one of only a few dry steam fields in the world.

Secondly, the Darajat wells are highly productive. While the worldwide average capacity of a geothermal well is 5 to 10 MW, a Darajat well can produce 40 MW of power.

The Sarulla Geothermal Plant

The Sarulla geothermal power plant, with 330 MW capacity, is the second-largest geothermal plant in Indonesia and is also one of the largest geothermal plants in the world.

The Sarulla geothermal resources, located in North Sumatra, were initially discovered by Unocal. Unocal conducted extensive exploration in the Sarulla geothermal working area from 1993 to 1998. It drilled a total of 13 deep wells and proved the existence of 330 MW of commercial geothermal reserves for 30 years.

However, due to the Asian financial crisis in 1997, the Unocal proposed power plant was not constructed until after the project was taken over by Sarulla Operation Limited (SOL).

Sarulla Operation Limited completed the power plant in 2016. The company is a consortium consisting of Medco Power Indonesia, Pertamina Geothermal Energy, INPEX, Ormat International, Itochu Corporation, and Kyushu Electric Power.  

The Sorik Marapi Geothermal Plant

The Sorik Marapi geothermal power plant located in Mandailing Natal in North Sumatra has a total installed capacity of 140 MW. as of October 6, 2022.

The Sorik Marapi geothermal plant was developed by ORKA Energy and operated by PT Sorik Marapi Geothermal Power.

The Sorik Marapi 45 MW Unit 1 power station came online in 2019. It was completed in a record time of three years, with the first drilling starting in October 2016 and the completion of the power station in October 2019.

The second 45 MW unit was inaugurated on 28 July 2021.

Its newest power station, the 50 MW Sorik Marapi Unit 3 station came online on October 6, 2022.

The company has a target to complete 50 MW Unit 4 and 50 MW Unit 5 power stations in 2023 and 2024 respectively to bring up its total eventual power generation capacity to 240 MW.

The Muara Laboh Geothermal Plant

Completed in 2019, the 85 MW Muara Laboh geothermal plant is the newest plant among the ten largest geothermal power plants in Indonesia.

The Muara Laboh geothermal plant is located in West Sumatra and is operated by Supreme Energy Muara Laboh (SEML).

It took the company 12 years to complete the geothermal project at 587 million US dollars.

The operator of the project, PT Supreme Energy Muara Laboh (SEML), is a consortium consisting of PT Supreme Energy, ENGIE, and Sumitomo Corporation.

Having proven reserves of 200MW, the company is in negotiation with PLN, the national power company, to build a second power generation unit.

The Ulubelu Geothermal Plant

Operating since 2012 and located at Lampung in Sumatera, the 220 MW Ulubelu geothermal power plant is operated by Pertamina Geothermal Energy.

The combined 220 MW power comes from the four 55 MW power generation units.

The Lahendong Geothermal Plant

The 120 MW Lahendong geothermal plant is located in Tomohon in North Sulawesi. The Lahendong plant started to operate commercially in 2001 and Pertamina Geothermal Energy (PGE) is the operator.

Its combined 120 MW power is generated from its six 20 MW power generation units.

The Wayang Windu Geothermal Plant

Located in the Bandung area in West Java, the 227 MW Wayang Windu geothermal plant began its commercial operation in 1999.

Star Energy operates the Wayang Windu geothermal assets under a joint cooperation contract with Pertamina Geothermal Energi.

The Dieng Geothermal Plant

The 60 MW Dieng geothermal power plant started to operate in 1998. The Dieng plant is located in the Dieng area in Central Java and is operated by Geo Dipa Energi.

Geo Dipa Energi is currently working on the following projects in the Dieng work area:

  1. Adding a small 10 MW power plant.
  2. Developing a 55 MW Dieng-2 power plant (PLTP Dieng Unit 2)
  3. Developing a 55 MW Dieng-3 power plant (PLTP Dieng Unit 3)

The Patuha Geothermal Plant

The 55 MW Patuha geothermal plant located at the Ciwidey area in West Java has been in operation since 2014.

Geo Dipa Energi as the operator is committed to drilling 12 new wells beginning in 2021 and constructing a second 55 MW power plant. Its long-term plan is to increase the Patuha power generation capacity to 400 MW.

The Lumut Balai Geothermal Plant

The 55 MW Unit 1 station of the Lumut Balai geothermal plant, located at Muara Enim in South Sumatra, started to operate commercially in 2019.

Pertamina Geothermal Energy as the operator of the Lumut Balai geothermal work area aiming to bring the total capacity of the power plant to 220 MW has started the project to build a second 55 MW power station.

Pertamina Geothermal Energy has awarded the Engineering, Procurement, Construction, and Commissioning (EPCC) contract to the Mitsubishi Corporation Consortium to construct the 55-MW Lumut Balai Unit 2 Geothermal Power Plant and the corresponding Fluid Collection and Reinjection System.

The Rantau Dedap Geothermal Plant

The Rantau Dedap geothermal power plant, located in South Sumatra, is the latest geothermal power plant that came online in Indonesia in 2021. Currently, it consists of two power stations, Unit 1 and Unit 2 having a total installed capacity of 98.5 MW.

The power plant is operated by PT Supreme Energy Rantau Dedap (SERD), a consortium consisting of Supreme Energy, Marubeni, ENGIE, and Tohoku Electric Company.

Here are the timelines for the Rantau Dedap geothermal project:

2010 – The concession for the Rantau Dedap was awarded to Supreme Energy.

2011 – Geoscientific exploration began.

2014 – Exploration drilling began.

2015 – A total of 6 exploration wells were completed by 2015.

2016 – The company confirmed the 92 MW of proven reserve capacity.

2018 – Power plant construction began.

2021 – Completed the Unit 1 and Unit 2 power stations.  

The 49.25 MW Unit 1 station was successfully synchronized to PLN’s power grid on 5 October 2021. PLN – Perusahaan Listrik Negara – is the national electricity company of Indonesia.

The Rantau Dedap Unit 2 station began its commercial operation on 26 December 2021.

PT Supreme Energy Rantau Dedap plans to further develop the geothermal potential in the Rantau Dedap geothermal work area with a total development target of 240 MW.

Geothermal is Rising in Indonesia

Sixteen geothermal power plants are operating in Indonesia currently. The list of the top largest power plants in Indonesia will likely change in 2023 as several new power plants will be completed in near future.

The Indonesian government is very keen to develop its vast geothermal resources to increase the contribution of renewable energy in its energy mix. Its targets are to increase the geothermal power generation capacity to 7500 MW by 2025 and 9300 MW by 2035.

To meet these targets, the government will provide funds to help companies in their exploration drillings, provide tax holidays, and remove certain taxes.

With a total of 265 potential sites for geothermal plants located across the country, the utilization of geothermal resources should continue to increase long into the future in Indonesia.

Written by Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled, and Produced

The Three Big Oil Companies in Indonesia before 1945

Sungei Gerong Refinery in South Sumatera in 1926

The first oil exploration in Indonesia started not long after Colonel Drake successfully drilled the first oil discovery well in Pennsylvania in the United States in 1859.

By 1869, Dutch businessmen in Indonesia, known as the Netherlands East Indies at that time, had noticed and recorded 53 oil seepage locations in Sumatera, Java, and Kalimantan.

Then the first oil well drilling in Indonesia took place in 1871 in West Java.

However, commercial discoveries were made only several years later when a Dutch businessman drilled successful exploration wells in Pangkalan Brandan in North Sumatera in 1885 and Sanga-Sanga in East Kalimantan in 1892.

These two discoveries caught the attention of the world and put Indonesia on the map as one of the countries with interesting oil potentials.

By 1900 there were already 18 oil companies searching for oil in the Netherlands East Indies (NEI). All these companies were either Dutch companies or non-Dutch companies registered in Nederland. The high level of activities resulted in significant oil discoveries in the early 1900s.

Following the oil discoveries, refineries were built in Pangkalan Brandan in North Sumatera in 1892, Sungei Gerong in South Sumatera in 1926, Balikpapan in East Kalimantan in 1922. By 1940, there were already seven refineries in NEI: three in Sumatera, three in Java, and one in Kalimantan.

In 1938, the daily crude oil production was about 140,000 BOPD and in 1953 it was about 190,000 BOPD.

The high level of oil production and refining activities from 1900 to 1940 made Indonesia well-known as one of the world’s significant crude oil producers and refined product suppliers at that time. In fact, Indonesia was so well-known for its oil it became involved in World War II.

Recognized as a significant oil producer, Indonesia was invited to become a member of OPEC 1962.

The three oil companies that produced about 90% of all the petroleum in Indonesia during the Dutch colonial period are:

  • BPM – Bataafsche Petroleum Maatschappij
  • STANVAC – Standard Vacuum Oil Company
  • CALTEX

Here are the amazing stories of these three big oil companies operating in Indonesia before 1945.


BPM

BPM is Bataafsche Petroleum Maatschappij, also called the Batavian Oil Company. Batavia, which is Jakarta today, was the center of the NEI government.

BPM was established in 1907 by KNPM (Koninklijke Nederlandsche Petroleum Maatschappij) also known as Royal Dutch Petroleum Company and Shell Trading and Transport Company to explore and produce oil in the Netherlands East Indies.

Royal Dutch Petroleum Company owned 60% and Shell owned 40% of BPM.

Before BPM was set up, there were already as many as 18 oil companies operating in the Netherlands East Indies (NEI) from North Sumatera, Java, Borneo, and all the way to Papua.

BPM quickly took over almost all of these companies and dominated the oil industry in Indonesia. By 1920, it had controlled more than 95% of crude oil production in Indonesia.

In 1921, as the government of the Netherlands East Indies wanted to take part in the booming oil business in Indonesia, NEI and BPM formed another company called NIAM (Nederlands Indische Aardolie Maatschappij).

Many big changes took place in the oil industry after Indonesia declared its independence in 1945. The first big change was the takeover by the government of Indonesia the NEI’s 50% ownership in NIAM.

This marked the beginning of an Indonesian government-owned oil company. It also started a working relationship between BPM and the government of Indonesia. With this relationship, BPM managed to extend its activities in Indonesia until 1965.

In 1965, BPM sold all its assets in Indonesia to the Indonesian state-owned company PN Permina for US$110 Million. Permina later became Pertamina.

BPM operations in Indonesia were extensive. They stretched from the western part of Indonesia to the eastern part of Indonesia.

Here are the operations of BPM in various parts of Indonesia.

BPM In Borneo

In 1907, right after it was formed, BPM acquired the oil fields and refinery in Balikpapan from Mathilda company. It also acquired the oil fields in Sanga Sanga and Tarakan which had been discovered previously by KNPM (Koninklijke Nederlandsche Petroleum Maatschappij).

BPM expanded its exploration and production aggressively in East Borneo and continued to discover several other fields in these areas.

On the small island of Tarakan, BPM drilled 700 oil wells and built a refinery.

Production continued to increase and in the 1920s the Tarakan wells produced about 18,000 BOPD, a third of the total oil production in the whole Dutch East Indies.

BPM in North Sumatera

BPM acquired from KNPM the oil fields and the refinery located at Pangkalan Brandan. BPM also took over the operations of the oil tanking and the oil export facilities at Pangkalan Susu. Pangkalan Susu was the first oil-exporting port in Indonesia.

BPM in Java

In Java, BPM acquired the oil assets of DPM (Doordsche Petroleum Maatschappij), a Dutch oil company established by Adriaan Stoop in 1887.

DPM had discovered and operated the Kruka Field and the Djabakota Field near Surabaya in East Java. DPM also had built the oil refinery in Wonokromo. Completed in 1893, this was the first oil refinery in Indonesia.

By acquiring DPM, BPM also became the owner of some thirty oil fields in East Java including another refinery located in Cepu which was built in 1894.

BPM In South Sumatera

In South Sumatera, BPM took over SPPM (Sumatera Palembang Petroleum Maatschappij). SPPM had been operating the oil fields in its concessions in Banyuasin and Jambi.

BPM also acquired the oil assets of MEPM (Muara Enim Petroleum Maatschappij). MEPM had discovered the Muara Enim field and built the Plaju Refinery.

BPM In Irian Jaya

In 1935 BPM expanded its search for oil into Irian Jaya. For this venture, along with other partners, BPM formed a joint venture company named NNGPM (Nederlandsche Nieuw Guinea Petroleum Maatschappij) with exploration rights for 25 years.

By 1938 they had discovered the Klamono oil field. followed by Wasian, Mogoi, and Sele fields.

However, for commercial reasons, these fields were not developed.

STANVAC

STANVAC – Standard Vacuum Oil Company – started as NKPM (Nederlandsche Koloniale Petroleum Maatschappij) in 1912. NKPM was set up in Nederland by the American company Standard Oil of New Jersey so it could explore for oil in Indonesia.

Since Indonesia was under the control of the Netherlands East Indies at that time, Jersey Standards had to set up NKPM as a Dutch-registered and Dutch-managed company with headquarters located in The Hague.

NKPM began to make exploration in Java and South Sumatera in 1914.

It was in South Sumatera NKPM found its liquid gold. Operating from the city of Palembang, it discovered the Petak field in 1914, the Trembule field, and the huge Talang Akar field in 1921. These discoveries prompted NKPM to construct the famous Sungai Gerong oil refinery.

In 1922 NKPM changed its name to SVPM (Standard-Vacuum Petroleum Maatschappij).

It also constructed the 130 Km long pipeline from Pendopo area to Sungai Gerong to bring the crude oil from the prolific Talang Akar field to the refinery.

The Sungai Gerong refinery began operating in 1926 and became the largest and important oil refinery in South East Asia.

It was so important that the refinery was occupied by Japanese forces from 1942 to 1945 during World War II.

To meet the increasing demands for petroleum products in Africa and the Asia Pacific, Standard Oil Company of New Jersey and SOCONY (Standard Oil Company of New York) jointly created STANVAC (Standard Vacuum Oil Company) in 1933.

This was a synergistic partnership as Standard Oil Company of New Jersey had the oil production capacity and SONONY had the marketing facility.

The newly created Stanvac in the Netherlands East Indies consisted of three companies: Standard Vacuum Petroleum Maatschappij (SVPM), the Standard Vacuum Sales Company (SVSC), and the Standard Vacuum Tankvaart Maatschappij (SVTM).

Stanvac took over all the assets of SVPM in Indonesia and became a full-fledged oil company involved in oil exploration and production, refining, transportation, and distribution in more than 50 countries.

However, Stanvac continued to operate under its Dutch company name – SVPM – in the NEI.

Stanvac produced oil from many fields in South Sumatera. The notable ones were Talang Akar, Djirak, Benakat, Radja fields.   

In 1934, Stanvac expanded its operations to Central Sumatera.  Here it discovered and developed the well-known Lirik field and later the Binio field.

Things began to change after World War II and the declaration of independence of Indonesia.

It was after the declaration of independence by Indonesia in 1945, to distance itself from its Dutch connection, Stanvac began calling itself  Stanvac Indonesia as its company name to show its American origin.

In so doing, Stanvac was able to keep its assets and continue to operate in the newly independent Indonesia.

In 1960, as Indonesia wanted to have more control of the oil operation and business, it introduced the 1960 Oil Law which stated that all foreign oil companies must operate as a contractor for the Indonesian government.

On 24 September 1963, Stanvac signed the “Contract of Work” agreement with Indonesia’s Pertambangan Minjak Nasional (Permina).

The contract allowed Stanvac to continue to have full control of its oil exploration and production operations in Indonesia. Under this agreement, Stanvac must sell its refinery within ten to fifteen years.

However, Stanvac had to sell its Sungai Gerong refinery to Pertamina in 1969.

Stanvac Indonesia continued to operate its oil fields until finally in 1995 it sold all its assets to Medco Energi for 88 million USD.

While Stanvac was operating in Indonesia, one of its parent companies, Mobil Oil, assumed the Arun block in Aceh in 1968. It went on to discover the super giant Arun gas field in 1971.

Interestingly, the two parent companies of Stanvac, Exxon and Mobil, merged in 1999 to become Exxon Mobil Corporation.

CALTEX

CALTEX was established in 1936 by Standard of California and Texaco to explore and produce oil in Indonesia and to expand its oil business in the Asia Pacific.

Earlier in 1924, The Standard of California had sent its team of geologists to Indonesia.

To operate in the Netherlands East Indies at that time, Caltex must obtain oil concessions from the government of NEI (Nederlands East India) who was the ruler of Indonesia at that time. To do so, in 1930, Caltex established NPPM (Nederlandsche Pacific Petroleum Maatschappij), a Nederland registered company with its headquarters located in The Hague. Also, the company must be run by Dutch nationals.

In the same year, Caltex received its first oil concession in the Rimba area which is now known as the Rokan Block in Central Sumatera.

Soon after that Caltex began to find oil, but it was in 1941 that  Caltex discovered the huge Duri field. Due to the high pour point of its low gravity crude oil, it was necessary to use steam-flood to drive out the oil. Due to the success of the steam flood method, the Duri field became known as one of the largest steam-flood projects in the world. In spite of the huge challenges to produce the field, it has produced more than 2.64 billion barrels of oil so far.

Several years later Caltex went on to discover another giant oil field, The Minas field.

The story of the Minas field discovery is very interesting. In 1940, at the beginning of World War II, Caltex had started the drilling of its exploration well in the Minas area. However, before the drilling was completed, Caltex had to abandon the drilling as the Japanese army was coming to occupy the area and to take over the oil facilities.

The Japanese army engineers resumed the drilling of the well in 1943 and discovered oil when it drilled down to 2600 feet deep.

At the end of the war, Caltex regained control of its oil assets and continued to investigate the Minas field. After drilling several additional wells, Caltex confirmed the discovery of the huge Minas oil field.

Caltex went on to discover many smaller oil fields in its concession area.

By the late 1950s, Caltex became one of the largest oil producers in Indonesia.  At its peak in 1973, Caltex produced about 1 million BOPD from the Duri, the Minas, and about 80 smaller oil fields. Caltex holds the record of having the highest daily crude oil production rate in Indonesia.

Caltex completed the construction of a crude oil export terminal in Dumai in 1958.

Caltex signed a work contract agreement with Indonesia in 1961 giving it the right to continue to operate the Rokan block until 2001. Later on, Caltex managed to obtain a work contract extension to operate the block for another 20 years until 2021.

The two owners of CALTEX, Chevron, and Texaco merged in 2001 to become ChevronTexaco Corporation. Later on, in 2005, ChevronTexaco Corporation dropped the name Texaco and renamed the company as Chevron Corporation.

Following the name change of its parent company, Caltex in Indonesia which was initially incorporated as PT Caltex Pacific Indonesia changed its name to PT Chevron Pacific Indonesia.

By 2008, Chevron Pacific Indonesia had produced 11 billion barrels of crude oil from the extremely prolific Rokan block.

Although the Rokan block has been producing oil for more than 80 years, it still has 2 billion barrels of estimated producible reserves. It is considered as an important block in Indonesia’s ambition to increase the daily oil production in Indonesia to one million barrels by 2030.

Although the name Caltex disappeared in Indonesia after the name change, the Caltex petroleum brand is still alive in many countries in the Asia Pacific.

Epilogue

These three companies of the past were great companies to work for. Since most of their oilfields were located in the middle of a jungle, the companies provided good and well-rounded facilities – schools, clinics, cafeterias, places for worship, sports, and entertainment – to their employees and their families.

Many people and children of those who had worked for these companies have fond and colorful memories of the companies.

To me, the one that is the most interesting is BPM.

The joint venture of Royal Dutch Petroleum Company and Shell Trading and Transport Company that formed BPM – Bataafsche Petroleum Maatschappij – in Indonesia in 1907 sowed the seed that eventually grew into the current giant Shell Oil Company.

Also, BPM had a role in the rise of Pertamina when Pertamina took over all the assets of BPM in 1965.

WRITTEN BY

Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced


 

The Famous Duri Oil Field

Duri to Dumai Road Construction in 1958

Eighty years ago, CALTEX discovered the huge Duri oil field in the Rokan block in Riau, Sumatera.

Oil was found at a shallow depth of 400 feet when CALTEX began drilling its exploration wells in 1941. However, the exploration drilling was interrupted due to the onset of the World War 2.

After the war ended, CALTEX managed to obtain the approval from the newly formed government of Indonesia to operate in the Rokan block under a work contract scheme. Eventually, oil production from the Duri field began in February 1954.

The giant Duri field – 10 km wide and 18 km long – is one of the many oil fields discovered in the Rokan block. Minas is another giant oil field discovered in this block.

Oil production peaked at 65,000 BOPD in the 1960s.

Due to the high viscosity of the low gravity oil, to enhance the production, the steam injection was introduced in 1985.

The Duri steam flood project was so successful that it became one of the largest and the best steam floods in the world.

Thanks to the successful steam injection, Duri oil production increased significantly to 185,000 BOPD.

After 30 years of the steam flood, the production had declined to about 50,000 BOPD by 2017.

With more than 2.6 billion barrels of cumulative oil produced, the giant Duri field is still producing today.

Chevron handed over the operatorship of the Duri field and the Rokan block to Pertamina in August 2021.

With Pertamina Hulu Rokan as the new operator, the Duri field and the Rokan block are undergoing a massive expansion.

More than 400 wells were drilled in the Rokan block with mostly done in the Duri field in 2022 and the company plans to drill another 500 wells in 2023.

Pertamina built a 17 MWp solar plant in the Duri field in 2022 to meet the electricity need of the field.



The New Seven SUPERMAJOR Oil Companies

The Seven SUPERMAJORS (2)

The Original SEVEN SISTERS

Before there was OPEC, there were the SEVEN SISTERS.

The Seven Sisters, a consortium of seven world’s largest multi-national oil companies, was formed in the 1950s.

Here are the original members of the Seven Sisters:

  1. Anglo-Persian Oil Company (now BP)
  2. Royal Dutch Shell
  3. Gulf Oil (Acquired by Chevron in 1985)
  4. Standard Oil of California (now Chevron)
  5. Standard Oil of New Jersey (now ExxonMobil)
  6. Standard Oil of New York – Socony (later became Mobil Oil and then ExxonMobil)
  7. Texaco (Acquired by Chevron in 2001)

Although the term “The Seven Sisters” was used for the first time in 1951, these seven companies had been dominating the oil industry since the 1940s. The Seven Sisters were so powerful that at one time, they controlled about 85% of the global oil and gas reserves.

Due to company mergers and acquisitions that took place in the oil industry in the last 40 years, the composition of the seven largest oil companies in the world had changed significantly.

The original Seven Sisters consisted of two European and five American oil companies whereas currently, the seven largest international oil companies in the world consist of four European and three American companies.

The New Seven Sisters

Due to mergers and acquisitions, several of the original members of the Seven Sisters no longer existed.

examples, Gulf Oil, Texaco and Standard Oil of California have merged to be known as Chevron, and Standard Oil of New Jersey and Standard Oil of New York merged to become ExxonMobil.

With the mergers and acquisitions the composition of the seven largest international oil companies therefore have changed.

Here are the new seven largest international oil companies in the world which are now commonly referred to as the seven SUPERMAJORS or the new Seven Sisters.

BP (British Petroleum)

British Petroleum is a British oil company that started as Anglo-Persian Oil Company in 1908 as a subsidiary of Burmah Oil Company. BP grew bigger and bigger by acquiring SOHIO (Standard Oil of Ohio) in 1978, then Amoco in 1998 and ARCO (Atlantic Richfield Company) in 2000.

BP operates in 79 countries with 70,000 employees. The London-based company produces 3.8 million BOEPD of oil and gas.

CHEVRON

Chevron began as Standard Oil of California as one of the successors of the original Standard Oil company, the company founded by Mr. John D. Rockefeller after it was broken up into several companies in 1911 under the Sherman Antitrust Act in the US.

Chevron became a huge oil company after acquiring Gulf Oil in 1985, then Texaco in 2001, and Unocal Corporation in 2005.

With headquarters in San Ramon, California, Chevron operates in 180 countries and employs more than 48,000 people. Its daily oil and gas production is about 3.1 million BOEPD.

EXXONMOBIL

ExxonMobil that began as Standard Oil of New Jersey is also another descendant of the original Standard Oil company. Standard Oil of New Jersey changed its name to Exxon in 1972, and later on, Exxon became ExxonMobil after it merged with Mobil Oil in 1999.

Operating in 58 countries, ExxonMobil has about 71,000 employees. It produces about 2.3 million BOE of oil and gas daily. The company is based in Irving, Texas.

ROYAL DUTCH SHELL

The formation of the Royal Dutch Shell group came from the merger of Royal Dutch Petroleum Company of the Netherlands and Shell Transport and Trading Company Limited of the United Kingdom in 1907. The Anglo-Dutch company was formed to compete against the powerful American oil company – The Standard Oil.

The Royal Dutch Petroleum Company, known as Koninklijke Nederlandse Petroleum Maatschappij in Dutch, had its root in Indonesia when it was formed in 1890 to produce the oil it discovered in Pangkalan Brandan in North Sumatera and later on in Balikpapan in East Kalimantan.

Royal Dutch Shell became a big player in LNG when it acquired BG Group in 2016.

From its headquarters in the Netherland, Shell operates in 70 countries and has 81,000 employees. The company’s daily oil and gas production is about 3.7 BOE.

TOTAL S.A.

Total, a French supermajor oil company, started in 1924 as Compagnie Française des Pétroles ( CFP). It later changed its name to Total CFP in 1985 and finally to Total in 1991.

The company grew even bigger after it acquired the Petrofina of Belgium in 1999 and then ELF Aquitaine in 2000.

Based in France, Total has operations in 130 countries and it employs more than 100,000 employees. It produces 3 million BOEPD of oil and gas.

ConocoPhillips

ConocoPhillips started as Conoco 1875 in the US. Conoco merged with Phillips Petroleum Company to form ConocoPhillips in 2002.

Based in Houston, ConocoPhillips involving only in the upstream part of the oil industry is the world’s largest independent oil company. With about 10,400 employees, its daily oil and gas production in 17 countries is around 1.3 million BOE.

ENI (Ente Nazionale Indrocarburi)

ENI, a supermajor oil company from Italy was formed in 1953, and then it acquired AGIP, another Italian oil company, in 2003.

From its headquarters in Rome, ENI operates in 79 countries. The company employs more than 30 thousand employees, and it produces a combined 1.7 million BOE of oil and gas daily.

Top Oil Producing Countries in 2021

The average daily total global oil production in 2021 is around 77 million barrels, 71% of which came from ten largest oil producing countries.
Here are the ten biggest oil producing countries in the world. The term BOPD refers to the number of barrels of petroleum liquid per day.
1. United States – 18.9 million BOPD
2. Saudi Arabia – 10.8 million BOPD
3. Russia – 10.8 million BOPD
4. Canada – 5.6 million BOPD
5. China – 5.0 million BOPD
6. Iraq – 4.1 million BOPD
7. United Arab Emirates – 3.8 million BOPD
8. Brazil – 3.7 million BOPD
9. Iran – 3.5 million BOPD
10. Kuwait – 2.7 million BOPD

WRITTEN BY

Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced

The Job of A Mudlogger

Mudlogging is one of the many important activities during drilling, especially in exploration drilling. Third-party service providers make up about half of the workforce on an offshore rig. With so many hi-tech and specialized operations being performed at all stages of the drilling operations it’s imperative that experts in their field perform these tasks.

The job of the “mudloggers” is to monitor the drilling operations from the time the well is spudded to the time the well is safely drilled, tested and secured for either production or abandonment.

“Mudlogger” is the generic term used to describe the field specialists who monitor the well and also collect samples for the geologist. The career progression for a mudlogger is to generally start as a sample catcher while they learn about the drilling operations, then progress to a mudlogger and with further experience, become a data engineer.

Sample Catchers

Dedicated sample catchers aren’t always part of the team but they often get “thrown in” as a complementary part of the mudlogging services. They don’t need to have any prior experience in working offshore or as a mudlogger, so it’s a very good entry-level job and is generally the starting position for a graduate geologist (or anyone else) who wishes to work offshore. Although you don’t need to be a geologist to be a sample catcher, most of them will be and will go on to get trained as a mudlogger.

Sample catching is without a doubt the least glamorous and lowest paid of all jobs on the rig…but you have to start somewhere! The role of a sample catcher is to provide the most basic geological data acquisition on the rig and to assist with all general activities when possible. The main duties of the sample catcher are:

  • Ensuring that representative geologic samples are caught throughout the drilling or reaming phases of the well program. This is done by collecting cuttings (drilled rock) samples, from the proper “lagged” (explained below) depths and at the proper intervals as required for evaluation. These samples are collected off the shale shakers, screened and washed, divided into correct portions, and packed into sets for the Client, partners, and government agencies. They may also have to assist in core recovery and packaging as required.
  • Preparing a clean “cuttings” sample on a sample tray for the wellsite geologist and mudlogger, who will then examine it under the microscope and describe the lithology of the drilled formation.
  • Assisting mudloggers and data engineers to perform regular and frequent calibration checks of instruments, perform normal routine maintenance of sensors and other equipment and also assist logging crew with rig-up/rig-down procedures.

 

Shaleshaker-Amanda
A shale shaker

 

The sample catcher reports directly to the mudlogging crew who will ensure his duties are performed correctly. This may include on-the-job training as required. They work out of the mudlogging unit, which is always close to the shale shakers and these are generally one or two levels below the drill floor.

The shale shakers are vibrating screens that separate the drilling fluid from the drilled rock cuttings. The “shaker house” is a very noisy place and double hearing protection must always be worn. There will be multiple shakers to accommodate the large volume of cuttings that can be produced when the drilling rate of penetration is high (i.e. they are drilling fast!). It’s a very “dirty” job and multiple layers of personal protective equipment need to be worn to prevent skin contact with the drilling mud, which can cause serious skin inflammation.

 

Mudloggers and Data Engineers (DE)

Mudloggers and data engineers are responsible for gathering, processing and monitoring information pertaining to drilling operations. They don’t only collect data using specialist data acquisition techniques – they also collect oil samples and detect gases using state-of-the-art equipment.

The information amassed by these guys is analyzed, logged and then communicated to the team that is responsible for the physical drilling of the well. Without the help of the mudlogger, the drilling operations would be less efficient, less cost-effective and much more dangerous. The mudlogger is vital for preventing hazardous situations, such as well blowouts.

They also provide vital assistance to wellsite geologists and write detailed reports based on the data that is collected. Being an entry-level position, employees will be given a mixture of ‘on-the-job’ training and expert in-house training courses, which cover different aspects of drilling operations. A major part of the training will focus on the use of specialist computer software.

Typically, you will need a degree in geology to start a career as a mudlogger. However, candidates with degrees in physics, geochemistry, chemistry, environmental geoscience, maths or engineering may also be accepted.

Along with the sample catchers and data engineers, the mudloggers work out of the mudlogging unit, which is a pressurized sea container-type of office, which is positioned close to the drill floor and shaker house.

The unit will have an air-lock compartment when you first enter it so as to maintain the positive pressure within the unit whenever somebody leaves or enters the unit.

This is the main control room for monitoring the drilling operations and is full of sophisticated and delicate equipment and computer systems. Positive pressure needs to be maintained to ensure the air pressure inside the container is higher than that of the outside area to prevent contamination of sensitive monitoring equipment – and also to ensure the safety of the crew working inside the unit should the outside air become contaminated through uncontrolled releases of hydrocarbons from the well.

 

mudloggingunit-amanda
A mudlogging unit

 

One of the most important tasks of the mudlogger is to oversee the collection of not only geological samples but also mud and gas samples from the well during drilling operations. To be able to do this accurately they have to know the exact “lag time” (or “bottoms-up time”) that it will take for the drilled cuttings or mud and gas to arrive at the surface after being drilled and circulated up the outside of the drill hole (annulus) while suspended in the drilling mud. The lag time maybe a few minutes in a shallow hole or as much as several hours in deep wells with low mud flow rates. To be able to work this time out accurately there are many factors that have to be taken into consideration. The lag time depends on:

  • the annular volume fluid
  • flow rate, which in turn requires knowledge of:
  • dimensions (internal diameter (ID) and outside diameter (OD)) of surface equipment, drill string tubular, casing and riser.
  • mud pump output per stroke, pumping rate, and efficiency.

While the computer’s software will work this out automatically, the calculated value may be incorrect if the operator has entered erroneous or incomplete values for the pipe or hole dimensions, or if the hole is badly washed out. This has to be monitored very carefully to avoid catching mud, gas and cuttings samples at incorrect depths.

Sensors

The mudloggers and DE’s monitor the drilling operations via a series of sensors that are placed at various locations around the drill floor, pit room, and shaker house.

The main drilling and mud parameters that are recorded are: hook movement, weight on hook, standpipe pressure, wellhead pressure, rotary torque, pump strokes, RPM, mud pit levels, mud density, mud temperature, mud resistivity, and mudflow.

These parameters are monitored in real-time and any deviances from the expected normal values must be immediately reported to the driller. The DE will view and monitor all the drilling parameters on a screen as shown below.

drilling parameters-amanda
A drilling parameter screen

 

The five most important monitoring tasks that the mudlogger and DE must watch out for are:

  • Rate of penetration increase, which could indicate they have drilled into a reservoir formation
  • Mud pit volume gain or loss, which could indicate the well is taking a kick, or losing fluid into the formation
  • Mudflow rate change
  • Mud density variation
  • Indication of oil or gas.

The mudlogging unit is a very confined workplace and there may be up to several people working in there at any one time, especially if it’s a “combo” unit, which houses the mudloggers, MWD engineers and possibly also the directional drillers.

Generally (but not always), the same service provider company performs all of these roles so it is quite common for data engineers to progress into a role as an LWD/MWD engineer. Other common career progressions for mudloggers/data engineers are as a wellsite geologist or drilling fluids engineer (mud engineer).

inside a mudlogging unit - amanda
Inside a mudlogging unit

The complete list of responsibilities of the mudloggers is too exhaustive to detail in this article but the above-mentioned roles are the main ones. Like most jobs on the rig, daily reports are a big part of the data engineer’s responsibilities.

The mudloggers report directly to the wellsite geologist, who are generally working in the mudlogging unit alongside them. Because the mudloggers are required to monitor the drilling operations from the commencement of drilling they will always be employed on a permanent rotating roster, which is generally 4-weeks on, 4-weeks off.

This article was written by Amanda Barlow, a wellsite geologist and published author of “Offshore Oil and Gas PEOPLE – Overview of Offshore Drilling Operations” for a beginner guide to working in offshore drilling operations, and “An Inconvenient Life – My Unconventional Career as a Wellsite Geologist”

Another great book you may want to read if you like to get an overview of oil exploration, drilling and production is “The Story of Oil and Gas”: How Oil and Gas Are Explored, Drilled and Produced”.