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 officially became a public company on 24 February 2023 following the completion of its initial public offering (IPO).
PGE booked a net profit of USD 127.3 million in 2022. This is an increase of almost 50% from its profit in 2021.
Part of the profit came from selling US$ 747,000 worth of carbon credits.
Currently, PGE is constructing its 55 MW Lumut Balai Unit 2 power plant which will come online by the end of 2024.
To further increase the installed capacity of its geothermal power, PGE plans to construct two 55 MW power stations in the Hulu Lais geothermal work area.
Current Projects of Pertamina Geothermal Energy
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:
Kamojang in West Java – 235 MW
Ulubelu in Lampung, South Sumatera – 220 MW
Lahendong in North Sulawesi – 120 MW
Lumut Balai Unit 1 in South Sumatera – 55 MW
Karaha in West Java – 30 MW
Sibayak in North Sumatera– 12 MW
The IPO of Pertamina Geothermal Energy
PGE officially became a public company on 24 February 2023 following the completion of its initial public offering (IPO).
The IPO of Pertamina Geothermal Energy is highly successful. It is oversubscribed 3.81 times. And this is significant!
Through the IPO, PGE offered to sell 25% of its shares, equivalent to 10.35 billion shares, at IDR 875 per share to the public.
Since the IPO is oversubscribed, PGE is successful in selling all the shares that it offered to sell.
This means PGE has successfully raised fresh funds worth IDR 9.056 trillion or 596 million USD.
The oversubscription shows there is huge interest from institutional investors in the business of clean energy and PGE.
One such company is MASDAR from UAE. Masdar is the biggest subscriber of PGE shares. Through the IPO it now owns 15% of the total PGE shares.
Masdar is one of the world’s largest clean energy producers with projects located in 40 countries. By investing in PGE, Masdar plans to further expand its interest in clean energy development in the Asia Pacific.
With its successful IPO and its new partner Masdar, PGE is set to expand its business in developing geothermal resources in Indonesia and beyond.
Jamin Djuang – Chief Learning officer of LDI Training
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.
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 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”.
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.
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.
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.
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 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.
Sail away from Bintan to East Kalimantan of two topsides for North Sisi and North Nubi fields of Pertamina Hulu Mahakam on 4 November 2021.
Oil and gas operators in Indonesia are investing USD 1.35 billion to expand and further develop their existing fields to increase their oil and gas production in 2022.
Here are the 12 oil and gas field expansion and development projects earmarked by SKK Migas to produce additional 19,000 barrels per day of oil and 567 MMSCFD of gas in Indonesia in 2022.
Bukit Tua Phase 2B Development At Offshore East Java
Operator: Petronas Carigali Ketapang II Ltd
Production Target: 14000 BOPD and 30 MMSCFD
Scope of work: Installation of Platform BTJT-B and drilling of development wells.
Completion date: 12 April 2022 (Completed)
Investment: US$ 117 million
Hiu Gas Field Phase 2 development at Block B Natuna
Operator: Medco E&P Natuna
Scope of work: Drilling two development wells Hiu A05 and Hiu A06
Target of production: 49 MMSCFD of gas
Investment: 45 million USD
Expected date of completion: May 2022
Jumelai Field Development in East Kalimantan
Operator: Pertamina Hulu Mahakam
Scope of work: Installation of platform JML1 and drilling of development wells
Production target: 45 MMSCFD of gas
Completion date: May 2022
Investment: US$ 65 million
Baru Gas Plant Modification in Riau
Operator: Energi Mega Persada (EMP Bentu)
Scope of work: Gas plant modification and suppling 30 MMSCFD of gas to Tenayan power plant of PLN
Expected date of completion: May 2022
Investment: 13.5 million USD
South Sembakung Production Facility Expansion in East Kalimantan
Operator: JOB PMEPS – Joint Operation Body of Pertamina and Medco EP Simenggaris
Target of production increase: 30 MMSCFD of gas
Expected completion date: June 2022
Investment: 9,2 million USD
Development of MDA and MBH fields at offshore Madura
Operator: Husky CNOOC Madura Ltd (HCML)
Scope of work: Drilling of 5 wells at MDA field and 2 wells at MBH field to supply gas to the East Java Gas Pipeline.
Target of production increase: A total of 175 MMscfd of gas from MBH in May 2022 and MDA in July 2022.
Total investment: 625 Million USD
Belida Gas Field Extension at Block B Natuna
Operator: Medco E&P Natuna
Target of production: 40 MMSCFD of gas
Investment: 78 Million USD
Expected date of completion: August 2022
Tanjung Field Polymer Flood
Operator: Pertamina EP in South Kalimantan
Scope of work: Full-scale polymer flooding
Target: Increasing oil production and oil recovery factor
Expected date of completion: September 2022
Investment: 19 million USD
MAC Field Development in Offshore Madura
Operator: Husky CNOOC Madura Ltd (HCML)
Scope of work: Installation of a platform and pipelines, and drilling of development wells
Target of production: 60 MMSCFD of gas
Expected date of completion: October 2022
Investment: 163 Million USD
North Sisi and North Nubi Development in East Kalimantan
Operator: Pertamina Hulu Mahakam
Scope of work: Installation of Platform WPS3 at North Sisi and Platform WPN4 at North Nubi, and drilling of development wells.
Production Target: A total of 90 MMSCFD
Expected Completion date: Second half of 2022
Investment: US$ 133 million
Bekapai Field Phase 3 Expansion
Operator: Pertamina Hulu Mahakam
Scope of work: Modification of Manifold Wellhead Platform BH and BE to accommodate 5 new development wells.
Production target: 27 MMscfd
Completion date: November 2022
Investment: US$ 28 million
YY Field Redevelopment at Offshore North West Java
Operator: Pertamina Hulu Energi ONWJ
Project scope: Relocating the wellhead platform due to the blowout of well YYA-1 in 2019
Target of production increase: 2000 BOPD and 1 MMSCFD of gas
Date of Completion: December 2022
Investment: 56.4 Million USD
This article is curated by Jamin Djuang, Chief Learning Officer of LDI Training, based on information provided by SKK Migas and other sources.
Data science is using analysis of past and current data to predict future performance or results.
Oil and gas companies collect a huge amount of data in their exploration, drilling, and production activities. They have huge volumes of unused and undervalued data.
With the advances in data science and machine learning, oil companies have begun to realize the value of the data they have been collecting.
They now realise that managing this data and using it as a strategic asset can significantly impact its operational success, increase safety and reduce operational cost.
For example, in exploration, seismic data and geological data, such as rock types in nearby wells, can be used to predict oil pockets.
In production, production data can be used to forecast future production capacity, schedule production, and determine the number of future wells to be drilled.
In drilling, engineers can use drilling data to determine the best drilling locations, reduce costs, improve safety and shorten the drilling time.
Here are several articles by Yohanes Nuwara on the applications of data science and machine learning in oil and gas operations.
A successful DST Test in East Kalimantan, Indonesia – Photo courtesy of Rick Patenaude
Drill-stem testing (DST) in exploration wells is the last step of oil and gas exploration. It is the moment of truth in the quest for the elusive oil and gas.
Witnessing a drill-stem test can be daunting as the company has invested a lot of time and money to find a new oil or gas field. As DST results can move the company’s share prices, during the test, the test results can only be communicated to a few people back in the company headquarters.
I have witnessed both successful DST and unsuccessful DST.
Here are the five moments of truth of a DST in exploration wells.
The first moment of truth is after the DST valve is open, you begin to see air bubbles showing up in a bucket of water that is placed on the rig floor. As the air bubbles become stronger, you know something is coming out from the test interval.
The second moment of truth is when you see the fire at the burner. When you see the flare, it confirms you have found hydrocarbon.
The third moment of truth is when we know the flow rates of the hydrocarbon fluids that come out from the well.
The fourth moment of truth is after you have measured the initial bottomhole shut-in pressure and the final shut-in bottomhole pressure. Reservoir engineers will love these two pressures to be about the same. If the final BHSI pressure is much lower than the initial BHSI pressure, it may indicate the reservoir is quite small.
The fifth moment of truth is when you know the fluid composition when you receive the fluid analysis report from the laboratory. This last moment of truth may kill all the prior excitements during a DST.
Here is to illustrate the significance and implications of the composition of the reservoir fluid.
In 1973, AGIP discovered the huge East Natuna gas field off northern Natuna Island of Indonesia. However, as the gas contains a very large percentage of CO2 – 71% – the huge gas field is still undeveloped today.
Finally, perhaps the best moment of truth in a DST is when a difficult and high-risk test, such as testing a high pressure or high H2S well, is completed successfully and safely, and the people involved in the test can leave the rig with a sense of accomplishment.
A jetty at Balikpapan Refinery – Photo shared by Zaldi Ansyah
In the efforts to increase the oil production of Indonesia, the government has identified 34 oil fields as candidates having potentials for enhanced oil recovery.
Here are the fields and their locations:
Rantau field – Aceh
Bangko field – Rokan Block
Bekasap field – Rokan Block
Kulim field – Rokan Block
Balam South field – Rokan Block
Petani field – Rokan Block
Pematang field – Rokan block
Zamrud field – Coastal Plain and Pekanbaru (CPP) block
Beruk field – CPP block
Pedada field – CPP block
Pusak field – CPP block
Sago field – Pertamina EP Asset 1 Jambi
Ramba field – Pertamina EP Asset 1 Jambi
Limau Q51 field – Pertamina EP Asset 2 South Sumatera – Limau
Jirak field – Pertamina EP Asset 2 South Sumatera – Limau
Belida field – Natuna D Alpha block
Melibur field – Siak, Riau
Gemah field – Jambi, South Sumatera
Makmur field – Jambi, South Sumatera
Kaji field – Rimau block
Semoga field – Rimau block
Iliran High field – Rimau block
Rama field – South East Sumatera (SES) block
Krisna field – SES block
Widuri field – SES block
E-main field – Offshore North West Java (ONWJ)
Zulu field – ONWJ
MQ field – ONWJ
Jatibarang field – Pertamina EP Asset 3 in West Java
Mudi field – Pertamina EP Asset 4 in East Java
Sukowati field – Pertamina EP Asset 4 in East Java
Tanjung field – Pertamina EP Asset 5 in Kalimantan
There is a saying that before you can lead others, you must first lead yourself. In other words, it is not possible to lead others if you cannot lead yourself.
Do you know how strong is your self-leadership?
Here is a quick and simple self-test to assess your self-leadership strengths and discover your weaknesses and opportunities for self-improvement.
Circle YES if you possess and demonstrate the following self-leadership qualities according to McKinsey and Company.
ON SELF-AWARENESS AND SELF-MANAGEMENT
Understanding own emotions and triggers. Yes / No
Self-control and regulation. Yes / No
Understanding own strengths. Yes / No
Integrity. Yes / No
Self-motivation and wellness. Yes / No
Self-confidence. Yes / No
ON ENTREPRENEURSHIP
Courage and risk-taking. Yes / No
Driving change and innovation. Yes / No
Energy, passion, and optimism. Yes / No
Breaking orthodoxies. Yes / No
ON GOALS ACHIEVEMENT
Ownership and decisiveness. Yes / No
Achievement orientation. Yes / No
Grit and persistence. Yes / No
Coping with uncertainty. Yes / No
Self-development. Yes / No
SCORING AND ASSESSMENT
Count the number of YES that you circle.
If your score is high, congratulations! It means you have many of the qualities of strong self-leadership and good self-management.
If your score is not high, you can improve your self-leadership by knowing the qualities you are lacking and embracing the right values that will enhance your self-leadership and self-discipline.
Here are inspiring quotes from Oprah Winfrey.
“It doesn’t matter who you are, where you came from. The ability to triumph begins with you. Always.”
Finally, to be a leader, you must have integrity. All your efforts will go to nothing if you don’t have it.
“Real integrity is doing the right thing, knowing that nobody’s going to know whether you did it or not.”
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 2024, there are more than one hundred geothermal power plants located around the world producing electricity with a total installed capacity of 16873 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 – 1904
The first and the oldest geothermal power plant in the world is in Larderello in Tuscany, Italy. The Larderello plant is celebrating 120 years in producing geothermal energy.
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 Enel group acquired Tuscany’s geothermal areas in 1962 and now operates 34 geothermal plants with a total capacity of 800 MW, supplying 34% of the electricity needs of the region.
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 916 MW making it the eight-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 3794 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 is the tenth largest geothermal-producing country in the world with a total installed capacity of 621 MW. Japan has the highest density of geothermal power plants. According to the Geothermal Research Society of Japan, there are 19 geothermal power plants in Japan with capacities of greater than 1 MW, and many small plants with capacities ranging from 20 KW to 250 KW.
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 Ahuachapán plant, completed in 1975, is the first geothermal power plant in El Salvador.
The journey of geothermal development in El Salvador began with exploration in 1955 for its geothermal potential, followed by the drilling of its first geothermal well in 1968.
The country’s first 30 MW Unit 1 Ahuachapán geothermal power plant was subsequently completed in 1975.
Two more power stations were later added – 30 MW Unit 2 in 1976 and 35 MW Unit 3 in 1981 – giving the Ahuachapán power plant a total installed capacity of 95 MW.
The Ahuacapan plant is served by 21 steam production wells and 9 reinjection wells.
Today El Salvador has two geothermal plants, the 95 MW Ahuachapan plant and the 104 MW Berlin plant giving the country a total installed geothermal capacity of 204 MW.
These two power plants generate 21% of the electricity in El Salvador. El Salvador is one of the countries having the highest percentage of electricity generated from geothermal resources.
The contribution of electricity from geothermal resources is set to increase in the future as the country is endowed with significant geothermal potential.
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 1935 MW is the third largest geothermal energy producer in the world. Its geothermal power generates 11% of the country’s electricity.
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.
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.
Over the years, under the management of KenGen – Kenya Electricity Generating Company – the Olkaria I geothermal power generation units has grown to six, with the latest additional unit, the 70 MW Olkaria I AU 6 completed in 2022.
Today, with a total installed capacity of 944 MW Kenya is the eighth largest geothermal energy producer in the world. Its geothermal power contributes an amazing 66% of the country’s electricity.
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 2356 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.
BOUILLANTE PLANT – THE CARIBBEAN – 1986
The first geothermal power plant in the Caribbean is the Bouillante plant.
The 5 MW Bouillante Unit 1 was commissioned in 1986, and the 10 MW Bouillante Unit 2 was completed in 2004.
Currently the 15 MW Bouillante plant is managed by Ormat. The company has plan to increase the geothermal power generation capacity in the Caribbean to 35 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.
QINGSHUI PLANT – TAIWAN – 2021
The Qingshui geothermal power plant is the first privately run commercial-scale geothermal power plant in Taiwan. With an installed capacity of 4.2 MWe, the plant is owned jointly by Fabulous Power Co and Taiwan Cogeneration Corp under build-operate transfer and rehabilitate-operate-transfer models with equipment from Ormat Technologies.
The Qingshui geothermal power plant started to operate in October 2021 and was officially inaugurated in November 2021.
Located in Yilan County, Taiwan, the reservoir temperature is around 180 degrees Celsius at a depth of 1,200 to 2,100 meters.
Its current 38 million kWh power output is enough to meet the demand of about 75% of the 10,000 households of the combined Datong and neighboring Sanshing townships.
Taiwan added the new 840 KW Renze geothermal power plant in 2023. Also Located in Yilan County, the power plant is operated by Taiwan Power Company (Taipower), a state-owned electricity company. The plant will produce 4.7 million kWh of electricity per year.
Taiwan government has a target of having a total of 20 MW of installed geothermal power generation capacity by 2025.
Aluto Langano – Ethiopia -2024
Ethiopia expects to have its first geothermal plant, the 35 MW Aluto Langano plant, in September 2024.
The Ethiopian Electric Power (EEP), the plant operator said the company has drilled 10 wells and tested 6 of them. The tests have confirmed a production capacity of 25 MW of power so far. EEP plans to drill four more wells.
When the plant is completed, the 35 MW phase 1 Aluto Langano plant will be the first geothermal plant in Ethiopia.
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.
This article is written by Jamin Djuang – Chief Learning Officer of LDI Training – based on information from various sources.
SSV Catarina drilled 5 Merakes development wells and the successful Maha-2 exploration well in ENI’s West Ganal block. Photo courtesy of Akhmad Syafrial.
The upstream oil and gas operators in Indonesia contributed 6.67 billion USD of revenue for the government of Indonesia in the first half of 2021. This amount is 91.7% of the full-year Indonesian government revenue target from E&P activities in 2021.
Mr. Dwi Soetjipto, the head of SKK Migas, is thankful that the 2021 first-half revenue contribution was better than expected in a meet-the-press event on 16 July 2021.
Here are the results from the oil and gas exploration and production activities in Indonesia in the first half of 2021 according to SKK Migas.
Oil Lifting Costs
The oil industry managed to lower the oil and gas production cost in 2021. The average production cost in the first half of this year is USD 12.17 per BOE (barrel of oil equivalent) whereas it was USD 13.71 per BOE in the same period last year.
Oil and Gas Production
The average oil production in the first half of 2021 is 667,000 BOPD. This is below the 705,000 BOPD target set by the government for 2021.
The average gas production is 5430 MMSCFD in the first six months of 2021. This is below the 5638 MMSCFD targets of the government for 2021.
To make up for the shortfall of oil and gas production, SKK Migas is asking the oil operators to speed up their work programs.
The average combined oil and gas production in the first half of 2021 is 1.64 million BOEPD.
Proposed Incentives
To stimulate oil and gas exploration and production in Indonesia, SKK Migas is pushing for government approval on several incentives.
The three incentives that are currently being proposed are:
Providing a certain type of tax holiday to all oil and gas operators
Reducing the processing fees charged by the Badak LNG plant to US$0.22 per MMBTU.
Lowering tax paid by companies who provide certain types of goods and services to oil companies.
Completed Oil and Gas Projects in Indonesia
Seven upstream oil and gas projects out of the 12 targeted for 2021 have been completed in the first half of this year, according to SKK Migas.
These 1.46 billion USD projects contributed 9850 BOPD of new oil and 475 MMSCFD of gas.
Here are the 7 completed projects: 1. First phase production from Belato-2 oil field by Seleraya Merangin Dua in South Sumatera
2. EOR in Jirak Field by Pertamina EP in South Sumatera
3. Development of KLD gas field by Pertamina Hulu Energi ONWJ
4. Gas Supply to the Balikpapan refinery from Bontang by Pertamina Hulu Mahakam
5. West Pangkah field development by Saka Indonesia Pangkah Ltd
6. Merakes gas field development in East Sepinggan block by ENI
7. Gas supply from South Jambi B block to PLN Jambi by Jindi South Jambi B.
The Jambaran Tiung Biru Project
SKK Migas is working closely with Pertamina EP Cepu on the development of the significant Jambaran Tiung Biru project. This gas field development project in East Java is categorized as a national strategic project.
The Jambaran Tiung Biru project is more than 90% complete and gas production is expected to come on stream in the fourth quarter of 2021.
Plans of Field Development
SKK Migas approved 14 plans of field development (POD) that will potentially increase the oil and gas reserves by 131.2 million barrels of oil equivalent (BOE).
Exploration Drilling and Discoveries
Oil operators completed seven exploration wells with the following results:
Gas discovery in two wells: Maha-02 and Fanny-02
Oil discovery in two wells: Hidayah-01 and MSDE-01A
Three dry wells: Barakuda-1x, NSD-1 ExpTail and Plajawan Dalam.
The P50 reserves from Well Hidayah-01 are 87 MMBOE. The P50 combined reserves from wells Maha-02, Fanny-02, and MSDE-01A are 154 MMBOE.
P50 reserves are oil and gas reserves that have a 50% or greater probability of being recovered from a petroleum asset.
Drilling, Workovers, and Seismic Survey Activities
Number of development wells drilled – 186
Number of exploration wells drilled – 13
Number of workovers – 309
Number of well services – 11307
2D seismic survey completed – 1917 Km
3D seismic survey completed – 673 Km2
This article is adapted by Jamin Djuang based on the information provided by SKK Migas. He is the Chief Learning Officer of LDI Training.
Welcome sign board at Caltex Rumbai camp entrance. Photo by Sasmito Adibowo.
After 97 years in Indonesia and producing more than 12 billion barrels of oil from the jungle in central Sumatera, Chevron Pacific Indonesia finally hands over its vast operation in the Rokan block to Pertamina Hulu Rokan on 8th August 2021.
The amazing story of Chevron Pacific Indonesia began in 1924 when Standard Oil of California (Socal), sent its exploration team to Indonesia to assess the oil potential in the basin in central Sumatera.
After the initial exploration expedition, Standard Oil of California set up the Dutch registered company, NV Nederlandsche Pacific Petroleum Maatschappij (NPPM), in June 1930 so it could conduct business in Indonesia, which was under the control of the Netherlands East Indies (NEI) at that time.
In 1936 NPPM became CALTEX when Socal and Texaco (Texas Oil Company) jointly formed a company called California Texas Petroleum Corporation to expand their operation in Asia, Australia, and New Zealand.
For most of the history of Chevron Pacific Indonesia, the company was known as Caltex or CPI (Caltex Pacific Indonesia). For this reason, the name Caltex or CPI is used frequently in this article to describe the activities and achievements of Chevron Pacific Indonesia.
The achievements of Caltex in Indonesia are awesome. Here are some of them:
It discovered two giant oil fields in Central Sumatera – The Duri and the Minas field.
It also discovered more than 100 oil and gas fields in the Rokan block and several other blocks.
It is the longest surviving oil company that began its operation in Indonesia as a Dutch company.
It is the biggest oil producer in Indonesia of all time. It produced more than 12 billion barrels of oil in Sumatera and its daily production reached 1000,000 BOPD at its peak.
It operated the famous and successful Duri steam flood.
Rokan block is the largest oil concession block in Indonesia.
It drilled a total of 16023 wells in the four blocks it operated: The Rokan block, the CPP block (Coastal Plain Pekanbaru), the Siak block and the MFK block (Mountain Front Kuantan).
MILESTONES OF CHEVRON PACIFIC INDONESIA
As the 8th of August 2021 marks the end of Chevron Pacific Indonesia, here are the key milestones of Caltex Pacific Indonesia’s operations in Indonesia.
1924
Standard Oil of California sent a team of geologists to Indonesia in March 1924 to survey the oil potential in Central Sumatera.
1930
Chevron registered the company Nederlandsche Pacific Petroleum Maatschappij (NPPM) in 1930 so it could operate in Indonesia which was under the rule of the Netherlands East Indies.
1936
Chevron and Texaco (Texas Oil Company) jointly formed California Texas Petroleum Corporation (Caltex) in 1936 to market its oil products in Asia, Australia, and New Zealand.
In Indonesia, NPPM became Caltex Pacific Petroleum Maatschappij (CPPM).
Caltex then received the right to explore and produce oil in an area in central Sumatera from the Netherlands East Indies. The area is now known as the Rokan block.
1940
Caltex made its first discovery in Indonesia when it discovered oil in the Sebanga field in Riau in August 1040.
1941
Caltex discovered the giant oil field Duri in 1941. Duri has the largest oil deposit in Southeast Asia at that time.
1944
Caltex discovered another giant oil field, the Minas field, in December 1944.
1945
Indonesia declared its independence in 1945. This is the event that changed the ways how oil companies operated in Indonesia.
1951
PT Caltex Pacific Indonesia, commonly referred to as CPI, was established in 1951 as an Indonesian company and was awarded the right from the government of Indonesia to continue to operate the Rokan block under a work contract scheme.
1952
Oil production from the Minas field started in April 1952 and was exported from Parawan and Pakning. The initial oil production from the Minas field was 15,000 BOPD.
1954
The Duri field started to produce oil in February 1954.
1955
Caltex discovered the Bekasap field in September 1955.
1958
Caltex built the first road that connected Pekanbaru and Dumai. It was also the first road that linked the east and west coasts of the island of Sumatra.
Caltex completed the Dumai oil export terminal in July 1958. At the same time, Caltex also completed the construction of oil pipelines from Duri to Dumai.
1959
Minas crude was exported from the Dumai terminal beginning in January 1959.
1963
PT Caltex Pacific Indonesia appointed Julius Tahija, the first native Indonesian as its president in 1963.
1965
Oil production from the Bekasap field began in June 1965.
Oil production from the Duri field during the primary recovery phase peaked at 65,000 BOPD in 1965.
1966
The Pematang field came online in July 1966 and the Pungut field in August 1966.
1967
Caltex cumulative oil production reached 1000,000,000 barrels in August 1967.
Caltex constructed an extensive pipeline and road networks to connect major fields such as Bangko, Bekasap, Pematang, Petani, and Kotabatak. These fields significantly increased its oil production output.
1969
The cumulative oil production from the Minas field reached 1000,000,000 barrels in May 1969.
1973
The Petapahan field began producing oil in January 1973.
Daily oil production of Caltex reached 1000,000 BOPD for the first time in May 1973.
1975
Caltex started the Duri steam flood pilot project.
1977
CPI completed the construction of the 350-meter long bridge over the Siak river connecting the city of Pekanbaru to Rumbai, and former President Soeharto inaugurated the bridge in April 1977. Rumbai is the area where the main office and housing complex of Caltex are located.
1980
Caltex completed its first oil Gathering Station under the Duri steam flood project. More gathering stations were later added as the Duri steam flood expanded.
1983
Caltex completed its main office building in Rumbai.
1990
The late former President Soeharto inaugurated the Duri Steam Flood on 3 March 1990.
1992
Caltex Pacific Indonesia obtained a 20-year extension to its production sharing agreement with Indonesia to operate the Rokan block until 2021.
1995
Caltex implemented the Strategic Business Unit management system in 1995.
1997
Caltex completed the Dumai Main Office in May 1997.
2000
Chevron acquired Texaco in October 2000.
2002
Caltex handed over the Coastal Pekanbaru Plain (CPP) block which it had acquired in 1971 to PT Bumi Siak Pusako – Pertamina Hulu on 18 August 2002.
The new operator is a joint operation body between PT Bumi Siak Pusako (BSP) which is owned by the local government in Riau and Pertamina.
2005
With the acquisition of Texaco by Chevron, Caltex Pacific Indonesia was renamed Chevron Pacific Indonesia in September 2005.
Chevron Pacific Indonesia came under the umbrella of Chevron IndoAsia Business Unit in 2005 along with Chevron Indonesia Company (ex-Unocal Indonesia Company), Chevron Makassar (the Makassar Deepwater Project), Chevron Geothermal Indonesia (Ex-Unocal geothermal projects in Darajat and Salak), Mandau Cipta Tenaga Nusantara, and Chevron Geothermal Philippines.
2008
Chevron Pacific Indonesia marked the 11th billion barrels of oil produced from its Sumatra operation in 2008.
2010
Chevron Pacific Indonesia handed over the operatorship of the Langgak block to PT Sarana Pembangunan Riau in January 2010.
2018
With the help of the successful steam flood, the Duri field’s cumulative oil production reached 2.6 billion barrels in 2018.
Total cumulative oil production of CPI from all fields reached 13 billion barrels.
2021
Chevron Pacific Indonesia hands over the prolific Rokan block to Pertamina Hulu Rokan on 8 August 2021. Rokan block with an area of 6220 KM2 is the largest oil concession block in Indonesia. Stretching over five “kabupaten” (regencies) in central Sumatera it produced oil from more than 12000 wells located in 80 fields. It also operates one of the biggest and most successful steam floods in the world.
The top ten producing oil fields in the Rokan block are Minas, Duri, Bangko, Bekasap, Balam South, Kotabatak, Petani, Pematang, Petapahan, and Pager.
Although the total oil production from the Rokan block has come down to 160,000 barrels per day, it is still a very significant oil asset for Indonesia as it is contributing 24% of the country’s total oil production according to SKK Migas.
Presidents of Caltex Pacific Indonesia Since 1963
One of the keys to the success of CPI is its adaptability. The company took initiatives to work effectively with both the central government of Indonesia and local governments, as well as the communities.
Caltex Pacific Indonesia decided in 1963 to Indonesianize the company. It appointed Mr. Julius Tahija as the first native Indonesian to be the company president. All its subsequent presidents have been Indonesians.
Here are the past presidents of Chevron Pacific Indonesia since 1963:
1. Julius Tahija, President & Chairman of the Board of PT Caltex Pacific Indonesia (1963 – 1977)
2. Haroen Al Rasjid, President & Chairman of the Board of PT Caltex Pacific Indonesia (1977 – 1993)
3. Baihaki Hamid Hakim, President & Chairman of the Board of PT Caltex Pacific Indonesia (1993-1999)
4. Humayunbosha, President of PT Caltex Pacific Indonesia (1999-2004),
5. W. Yudiana Ardiwinata, President of PT Chevron Pacific Indonesia (2004-2005),
6. Suwito Anggoro, President of PT Chevron Pacific Indonesia and Deputy Managing Director Indonesia Business Unit (2005-2010),
7. Abdul Hamid Batubara, President of PT Chevron Pacific Indonesia and Deputy Managing Director Indonesia Business Unit (2010-2014),
8.Albert B. M. Simanjuntak, President of PT Chevron Pacific Indonesia and Deputy Managing Director IBU (2014-2021),
Epilog
Although the signboard with a Caltex logo will no longer be seen at the entrance of Rumbai camp, the company will continue to be remembered by people who have worked for the company and lived in the surrounding communities.
Caltex will be remembered not just for what it did in the oil fields, but it will also be remembered for what it did for the surrounding people and communities.
Here are some of the most notable legacy of Caltex:
Building the first state senior high school (SMAN-1) in Pekanbaru in 1957
Completion of the 350 meter-long bridge over the Siak River in 1977.
Establishing the polytechnic college – Politeknik Caltex Riau in 2001.
Lastly, here is a nice comment from George Barnett on his experience working for Caltex in the early 1970s.
“I had the honor of working as a young Caltex construction engineer on the Bangko, Balam, Mengala, Kotabatak project, including the looping of the pipeline from Minas to Dumai, a new export wharf, and a new gas turbine power plant in Minas, actually fueled by crude. Years later, I worked on the conceptual front-end studies for the proposed Duri Steamflood project, in which we looked at alternative fuels for the steam boilers from railroads bringing coal from South Sumatra, to geothermal power and biomass. Pertamina showed genius in wanting the best, most efficient, and effective environmental solutions.
My fondest memories extend especially to the wonderful people of Sumatra, their genuine hard work ethic, belief in their country, their strong conservative religious roots, their empathy, understanding and friendship!”
George Barnett shared more of his experience working for Caltex in Central Sumatra.
“The construction project was to bring on stream the Bangko, Balam, South Mengala, and Kotabatak oil fields. It also involved a new parallel crude pipeline from Minas to Duri, then on to Dumai with a new export wharf and infrastructure. I recall total added production was 246,000 bpcd, and at the end, the exports did spurt to 1,000,000 bpcd during a maximum production trial.
Great memories! One of which was that the Indonesian workers had a great knack for developing mechanical skills. The CPI concession had ~348 pieces of Caterpillar equipment alone. I was introduced to operating bulldozers, cranes, earthmovers, and such. We all – a workforce of nearly 3,500 – completed a then world-class project in 18 months.
Beautiful country and people. I had a 135cc motorcycle and was able to visit a lot of remote regional communities, including as far as Bukittinggi. Saw wild animals from elephants to orangutans to tigers and giant monitor lizards. And intermingled with the Sumatran indigenous Sakai people. All are my fondest memories of a 35-year career in the oil industry.”
This article is written by Jamin Djuang. He had been in Rumbai and Duri conducting training for Caltex and had traveled the private road connecting Rumbai and Duri. He enjoyed eating in the Caltex cafeteria in Rumbai, where they served both delicious Indonesian and Western food.
Some of the information in this article was provided by Mr. Elthaf, who worked for CPI in the Minas field for 36 years.
Training and development have become ever more important as companies face significant skills gaps during this rapidly changing business environment.
How will you know if your training meets the skills gaps and generates the desired impacts to make your company successful?
The original model of training evaluation developed by Raymond Katzell suggested that training should be evaluated in four steps:
Step 1: Measure reaction.
Step 2: Measure learning.
Step 3: Measure behavior.
Step 4: Measure results.
This is the model that Kirkpatrick promoted for many years. Dr. Jack Phillips, the author or editor of more than 100 books, went further to define the methodology and add another step. He, with many other practitioners, began to call these levels. These levels of evaluation are
Level 1 – At level one, the results of training are assessed based on participants’ reactions to the training and the action plan submitted by the participants. This is commonly done immediately after the training.
Level 2 – At level two, the results of training are assessed by how much learning is acquired by participants. This is done by conducting some form of testing.
Level 3 – At level three, the training evaluator will find out if the acquired skills, knowledge, or attitude (SKA) are applied and implemented by the trainees. This is usually done several weeks or months after training.
Level 4 – At level four, evaluators assess the impact, both tangible and intangible, of the training several weeks or months after the training. Examples of tangible impacts are cost savings, higher productivity, better quality, sales increase, etc. Examples of intangible benefits are attitude improvement, better communication, etc.
Level 5 – At level five, evaluators measure the return on investment of training or any other people development program.
Phillips went on to develop process standards and pushed the methodology through the ROI Certification process. Today, over two-thirds of the Fortune 500 companies use this methodology, 26 governments around the world, many NGOs, non-profits, approximately 300 health care organizations, and 150 universities. It is now the most used evaluation system in the world.
ROI is an important measure that is used to show the efficient use of funds. Management is interested in ROI as it compares the actual monetary benefits of the training program relative to the total costs of the training.
STEPS TO MEASURE THE ROI
Here are the steps to measure the ROI of a training program.
Design the training based on business needs.
Plan the training to be evaluated at all levels.
Design the training such the skills, knowledge, or attitude taught can be applied and implemented on the job.
Collect Level 1 data – reactions and action plans of trainees- at the end of training.
Collect Level 2 data – learning – at the end of training.
Collect Level 3 data – application and implementation – several weeks or months after training.
Collect Level 4 data – Both the tangible business impacts and the intangible impacts – several weeks or months after training.
Isolate the effect of the program by identifying other factors that may impact the outcomes of the program. This is a critical aspect in producing credible ROI results.
Convert Level 4 data into monetary values of the training benefits.
Annualize the monetary values to determine the monetary benefit of the training over 12 months.
Collect data on the total costs of training.
Calculate the ROI using this formula. ROI = (Benefits – Costs)/Costs x 100%
THE BENEFITS OF MEASURING ROI
As the need for skill-building is increasing and the training budget is getting bigger, it is important to know whether you are getting positive values from your investment in training.
When you have the ROI data to prove to management the value of your training, you will get more supports for the training programs you plan conduct in the future.
Dr. Jack J. Phillips is the pioneer in measuring the ROI in training. Over the past 20 years, Dr. Jack Phillips and Dr. Patti Phillips have trained and certified thousands of training professionals on the ROI Methodology. More than two-thirds of the Fortune 500 companies are applying this methodology in the training they conduct.
How about your organization? Does your management ask you to measure the ROI or financial benefits of your training programs? Have you done this before? Do you have the competency and confidence to do it?
