The first offshore oil platform decommissioning in Indonesia was completed in November 2022. The decommissioning of the EB platform of the giant Attaka oil field was carried out by Pertamina Hulu Kalimantan Timur as the field operator and KHAN Co. Ltd. of South Korea.
This platform decommissioning is called the Attaka Rig to Reef Project aimed to promote an effective and environmentally friendly approach to protect the ecosystem and develop future ecotourism. In the project, the platform was removed and put in a conservation area.
As many offshore oil and gas fields in Indonesia were discovered in the late 1960s and early 1970s, many of their platforms are nearing the end of their productive life, such as the ones in the Offshore North West Java block and the West Seno field according to SKK Migas.
The prolific Attaka field was discovered by Unocal along with its partner, INPEX, in 1970 in the East Kalimantan offshore working area. The Attaka field is the first commercial offshore oil field in Kalimantan. At its peak, it produced 110,000 barrels of oil and 150 MMSCF of gas per day. After more than 50 years of production, its daily oil production today has declined to less than 5000 BOPD.
Pertamina Hulu Kalimantan Timur became the field operator in October 2018.
The Gagak Rimang FSO operated by ExxonMobil Indonesia.
The two top oil operators in Indonesia account for more than 50% of the total crude oil production in Indonesia in 2023. They are Pertamina Hulu Rokan and ExxonMobil Cepu Limited.
PERTAMINA HULU ROKAN
Pertamina Hulu Rokan, the operator of the massive Rokan block, is the current largest oil producer in Indonesia.
Oil production from the Rokan block has been increasing through its ongoing massive development well drilling program since PHR acquired the block from Chevron in August 2021.
The oil production from the Rokan block went above 172,000 BOPD recently. This is the highest daily production since the acquisition.
PHR has drilled 825 development wells in the Rokan block. While the massive development drilling is continuing, PHR has started drilling the first well to explore the unconventional hydrocarbon in the Rokan block.
EXXONMOBIL CEPU LIMITED
ExxonMobil as the operator of the prolific Banyu Urip oil field in East Java produces 164,000 BOPD from the field.
EMCL was the biggest oil producer in Indonesia at one time, producing more than 200,000 BOPD during its peak. However, producing since 2008, oil production from the Banyu Urip field is declining.
To boost its production, ExxonMobil will drill five infill wells targeting the carbonate formation and two infill wells targeting the clastic formation in 2024.
This seven-well drilling of the field optimization program is expected to increase oil production by 18,000 BOPD and add 42 million barrels of oil reserve.
EMCL has contracted PDSI (Pertamina Drilling Services Indonesia) to drill the seven wells in 2024.
With an amazing 125 years of history in Indonesia, ExxonMobil is currently the oldest oil and gas operator in Indonesia. ExxonMobil started in Indonesia as Stanvac. Here is more for your reading on the history of ExxonMobil Indonesia – The Three Big Oil Companies in Indonesia before 1945 – https://oilandgascourses.org/the-three-big-oil-companies-in-indonesia-before-1945/
Currently, LNG production in Indonesia comes from three LNG plants: The Badak LNG, the Tangguh LNG, and the small 2 MTPA Donggi-Senoro LNG plant.
In the last five years, Indonesia’s LNG production volume declined by 23%, from 18.2 MTPA in 2018 to 14 MTPA in 2022 due to the declining production from the Badak LNG plant.
The Badak LNG plant, one of the largest LNG plants in the world has been in operation for 45 years since it began production in 1977 in East Kalimantan.
The Badak LNG plant comprising eight trains has a total production capacity of 22.6 MTPA. However, due to the declining gas supplies from its surrounding oil and gas fields in East Kalimantan, only two trains are now in operation.
Due to the issue of dwindling gas supplies, most of the LNG from the Badak plant is sold as short-term or spot cargoes in 2022 as it cannot secure medium and long-term deals.
The Tangguh plant is carrying the heavy load of producing the LNG for the export market. Started producing LNG in 2009, the Tangguh plant currently consists of two trains with a total production capacity of 7.6 MTPA.
Most of Indonesia’s LNG cargoes are sold in the Asia Pacific region as expected. However, thanks to the recent high LNG spot prices, some cargoes also reached European markets.
For the domestic LNG market in 2022, the “real” LNG consumption has reached 3.17 MTPA, about 23% of annual production. This number is, unfortunately, lower than the annual LNG volume consumed by some neighboring countries like Thailand (8.2 MTPA), Singapore (3.7 MTPA), and Bangladesh (4.4 MTPA).
Good progress is coming from the performance of Perta Arun Gas, which is operating the Arun LNG Regas Terminal and LNG Hub in Aceh. So far, almost one metric ton of LNG volume has been unloaded into Arun LNG tanks and later reloaded for final delivery.
FUTURE
In the future, the Tangguh and the future Masela plants will play a key role in positioning Indonesia as one of the top LNG producers with a total plant capacity of 33 MTPA.
The Tangguh Train #3 which is set to go on stream by the end of 2023 will increase the total Tangguh LNG plant capacity by 3.8 MTPA to 11.4 MTPA.
With the divestment of Shell’s interest in the Masela block, the Abadi LNG plant with a capacity of 9.5 million tons per year is expected to be completed by 2030.
Currently, up to 17 MTPA of future volume is still uncontracted. However, according to SKK Migas, there are huge interests in Indonesia’s LNG.
Fishing operation recovering a 12 1/4-inch directional drilling BHA.
Situations, where fishing is necessary, can arise during oil and gas well drilling or workover operations.
Fishing situations occur when equipment is stuck or lost in the hole. They are quite common in oil and gas well drilling or workovers. It happens to one in five wells.
While some fishing operations are simple, some of them can be very difficult or even impossible.
When fishing is impossible or deemed too difficult, the operator can opt to either redrill a new well or to sidetrack by opening a new track in the existing hole to bypass the fish.
Here are the two commonly asked questions when an operator is in a fishing situation.
Should we fish or not?
How much time should we spend to recover the fish?
Many fishing jobs are difficult and require special tools and the expertise of a fishing specialist. However, even with the best tools (which may have a high daily cost) and procedures, sometimes the fishing attempt fails or takes a long time.
It is vital to know everything possible about the fish and fishing conditions before starting the job so you can ascertain the level of difficulty. The operator should consider some fishing jobs impractical from the very start. For example, drill collars accidentally cemented in or engulfed in barite are nearly impossible to recover and are not worth the cost, even if they are recovered. In these situations, you should not proceed with fishing and should begin side-tracking instead.
When it is difficult to decide what is fishable and you do not know the probability of success, it is best to estimate the cost of side-tracking and determine how long to fish.
The cost of side-tracking can be estimated easily. It takes about 5 days to set a cement plug on top of a fish and kick off the hole to bypass the fish.
You can estimate the cost of drilling a new hole to reach the original total depth if you know the:
rate of penetration
length of the original hole.
It is also important to recognize when it is time to stop fishing and start re-drilling. You need to determine how long to fish so that the cost of the fishing operations and lost drilling time do not exceed the cost of side-tracking.
Generally, you should stop fishing and decide to sidetrack the well when the cost of fishing has reached about half the cost of side-tracking.
The following equation calculates the number of days that should be allowed for fishing.
D = (V + CS)/(R + CD)
where:
D = Number of days to be allowed for fishing
V = Replacement value of the fish
CS = Estimated cost of side-tracking
R = Daily cost of fishing tool rental and services
CD = Daily rig operating cost.
After you calculate the maximum number of days to spend fishing, you may realize that it will take longer than the allotted time to fish. In this case, it would be better off to side-track instead of attempting to fish.
This article is written by Rick Patenaude. Rick started his oilfield career in the Powder River Basin of Wyoming in the mid-1980s. He joined Weatherford as a Fishing Tool Supervisor in 1995 and worked throughout the Rocky Mountain Region until 2003. Rick transferred to China in 2003 to support Weatherford’s operations in the Pearl River Basin and Bohai Bay until 2006. Rick was then transferred to Jakarta to support the growing well-intervention market for both national and international clients. In 2012 Rick was assigned to Balikpapan as Project Manager Fishing & Re-Entry Services for Chevron’s West Seno Extended Reach Drilling Project. Upon completion of the West Seno Project Rick returned to Jakarta and began supporting operations throughout the Asia Pacific Region including New Zealand, Australia, India, Brunei, Malaysia & Japan.
The photo above shows the fish recovered with a skirted screw-in sub after a successful wash-over operation to burn off the blades on the integral bladed stabilizer. The fish is a 12-1/4″ OD directional drilling BHA.
El Salvador is one of the few countries in the world which has a high percentage of electricity produced from geothermal resources.
Its two geothermal power plants, the 95 MW Ahuachapan, and the 109 MW Berlin plants with a combined installed capacity of 204 MW, supply 21.7% of the electricity needed in the country.
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.
Ahuachapán’s three power stations are supported by 21 steam production wells and 9 reinjection wells.
Following the success of the Ahuachapan plant, LaGeo, the operator began building a second plant, the Berlin geothermal plant in 1992.
The Berlin plant consisting of four power stations with a total installed capacity of 109 MW is supported by 16 steam production wells and 23 reinjection wells.
El Salvador can easily double its electricity production from geothermal resources as it still has more potential to develop. It has an estimated 600 MW of untapped geothermal resources in the following areas:
Indonesia produces around 5.3 billion SCF of gas daily. Around 68% of its produced gas is sold to domestic users in the form of pipeline gas and LNG.
Currently, around 30% of its produced LNG is sold to domestic users and the rest is exported.
Indonesia wants to increase the use of LNG to provide the gas needed for domestic use. However, the current prices of LNG for the domestic market are considered too high by consumers as they are around $6 per MMBTU higher than the gas delivered via pipeline. The current oil indexation pricing of LNG is also considered unfavorable to consumers as the prices can escalate drastically.
What should be the price of Indonesia’s LNG for domestic sales?
This article provides a thorough analysis of the current gas and LNG prices for sales in Indonesia including the pricing policy, and a suggestion for reducing the price gap between LNG and pipeline gas.
CURRENT PRICES OF GAS AND LNG IN INDONESIA
Figure 1 – LNG and gas prices in Indonesia
Currently, there are big gaps between LNG prices and the downstream gas prices paid by gas consumers in Indonesia. As the country wants to increase the use of LNG to support the gas market, it should find a pricing mechanism to reduce those gaps. Otherwise, all LNG, either from domestic or international sources, will find it hard to find buyers in the Indonesian gas market.
The LNG costs shown in the graph are the landed prices at the receiving terminal plus applicable import duties/taxes of around 17% and regasification costs of around $2.5 per MMBtu. Downstream pipeline transportation fees are note included here.
The downstream gas market in Indonesia has several gas price layers:
Prices of gas fixed by the government for Household and Prioritized Industries – $5-6 per MMBTU.
Gas Market served via downstream pipelines by PGN (Perusahaan Gas Negara) – $6-9 per MMBTU.
Gas from LNG supplied by Nusantara Regas FSRU to PLN power plants in Muara Karang and Tanjung Priok – $9-12 per MMBTU.
LNG PRICES FROM 2017 – 2027
Figure 2 – LNG and gas prices from 2017 – 2027
Figure 2 shows how LNG prices moving along the Indonesian gas prices and their price spread from 2017 to 2027. The period includes the event of Covid-19 when oil prices dropped below $50 per barrel and the Russia-Ukraine conflict when oil prices climbed above $80 per barrel.
As the graph shows big swings in the price spread between domestic LNG and gas due to international events. It reached $10 per MMBTU during the onset of the Russia-Ukraine conflict.
The graph also shows the domestic LNG supply is still the cheapest option for Indonesia while US LNG could bring better prices at times.
A NEW LNG PRICING MECHANISM FOR DOMESTIC USAGE
Figure 3 – LNG cost-pass-through illustration
It will be difficult for LNG to play a big role in supporting the growth of Indonesia’s gas market with the current LNG pricing scheme. As the need for gas will continue to grow, with all existing regasification terminals in Jakarta, Lampung, and Arun as well as future additions, the gas market can double in size if the LNG price is priced correctly.
So, is there a way to change or adjust the LNG pricing mechanism for domestic sales, and at the same time keep sufficient return on investment for all involved parties?
Is it possible to reduce the net cost of gas derived from LNG to consumers to around $6-9 per MMBTU, the price that is within the paying capability of domestic users?
Cost-Pass-Through LNG Pricing
One solution is to apply the concept of a “cost-pass-through pricing mechanism” instead of oil indexation.
To illustrate this concept, the Badak LNG plant in Bontang is used as a study case.
The Badak plant is chosen for discussion because it is fully depreciated as it has been in operation since 1978, and due to its strategic location, it easily covers the entire part of Indonesia within 2,000 nautical miles.
The followings are best-estimate cost component figures used to calculate the Cost-Pass-Through price of LNG for long term or medium-term domestic sales and purchases. All these numbers meet the required project returns of each party.
Upstream gas cost in the form of a fixed number with an escalation factor subjected to governmental approval. For the case of Badak LNG, as there is no more cheap gas available, the upstream gas is assumed at a fixed cost of USD 4.5/MMBTU
LNG production cost, covering the operations & maintenance cost is fixed at USD 0.50/MMBTU
Shipping cost, a fixed cost of USD 0.5/MMBTU based on a fixed Time Charter Rate for long term or medium-term contracts.
Trading margin at USD 0.40/MMBTU
Regasification cost, averaging a fixed cost of USD 2.5/MMBTU among existing regassification terminals.
Based on these figures, the total cost of gas derived from LNG applying the cost-pass-through concept is around $8.4 per MMBTU. This is within the price range of $6-9 per MMBTU.
In conclusion, unlike the existing oil-indexed LNG pricing formula for domestic sales, in this “cost-plus-through” scheme all cost components in the LNG pricing are fixed numbers. This is good and fair for Indonesian gas consumers because the supply is sourced within the country and the costs are not affected by any geopolitical risks and fluctuation of international energy references like oil prices.
When the gas derived from LNG produced from big plants like the Badak plant could be delivered below the USD 9/MMBTU level, it will certainly boost the demand for gas in Indonesia especially in its remote areas.
Sun rising at Mahakam River. Photo courtesy of Rick Patenaude
With many big, depleted oil and gas reservoirs, Indonesia has a huge capacity and the potential to become a regional hub for storing CO2. It has an estimated capacity to store more than 400 gigatons of CO2.
Developing facilities for storing captured CO2 is not just a way to reduce the amount of CO2 released into the atmosphere, it can also generate revenues of around $50 per ton of CO2 stored.
As the first step, Pertamina is working with ExxonMobil to study the CCS feasibility of its depleted reservoirs in the Sunda-Asri basin. Pertamina and ExxonMobil will come up with a commercial model design for the regional CCS hub development in the working area of PT Pertamina Hulu Energi OSES.
Here are the assets and areas that the Ministry of Energy and Mineral Resources has identified as having the potential for carbon storage, carbon capture, or carbon utilization.
Carbon Storage (CS) • Arun reservoir
Carbon Capture, Utilization and Storage (CCUS) with EOR • Gemah field • Ramba field • Sukowati field • Tangguh field • Jatibarang field
Carbon Capture and Storage (CCS) • Abadi field • Sakakemang field
CCS/CCUS Hub • Central Sumatra Basin • Kutai basin • Sunda Asri basin • East Kalimantan
Here is an update on CCU-CCUS projects in Indonesia announced during the 14th Clean Energy Ministerial meeting hosted by India, on 19-22 July 2023 in Goa.
Approved Plan CCUS Project BP Berau project – Ubadari Field Development, and Vorwata EGR/CCUS and onshore compression. Increase gas production and reduce CO2 emissions by up to 33 MT by 2045.
Potential Future CCU-CCUS projects ▪ PT Pertamina EP Gundih CCUS-EGR Project. Potentially reduce 3 MT of CO2 for 10 years. ▪ PT Pertamina EP Sukowati CCUS-EOR Project. Potentially reduce CO2 10 MT for 15 years. ▪ Repsol Sakakemang CCS Project. ▪ Abadi CCS Project. Reducing native CO2 2.8 MTPA or 70MT for 25 years. ( Inpex, Pertamina and Petronas) ▪ Blue Ammonia + CCS in Central Sulawesi (Pertamina, PT PAU, JOGMEC, Mitsubishi & ITB), Potential CO2 reduction around 19 MT for 20 years. ▪ Arun CCS (Joint venture of Carbon Aceh & PEMA). ▪ Ramba CCUS (Pertamina). ▪ Central Sumatera Basin CCS/CCUS Hubs (Pertamina & Mitsui). ▪ Asri Basin CCS Hubs (Pertamina & ExxonMobil). ▪ East Kalimantan CCS/CCUS Study (Pertamina & Chevron). ▪ East Kalimantan CCS/CCUS Study (Kaltim Parna Industri & ITB), surface facility study. ▪ CCU to Methanol – Pertamina Refinery Unit V (Pertamina & Air Liquide) ▪ Gemah field CCUS CO2-EOR. ▪ Jatibarang CCUS CO2-EOR (Pertamina & JOGMEC). Ongoing field trial.
The first offshore oil platform decommissioning in Indonesia was completed in November 2022. The decommissioning of the EB platform of the giant Attaka oil field was carried out by Pertamina Hulu Kalimantan Timur as the field operator and KHAN Co. Ltd. of South Korea.
This platform decommissioning is called the Attaka Rig to Reef Project aimed to promote an effective and environmentally friendly approach to protect the ecosystem and develop future ecotourism. In the project, the platform was removed and put in a conservation area.
As many offshore oil and gas fields in Indonesia were discovered in the late 1960s and early 1970s, many of their platforms are nearing the end of their productive life, such as the ones in the Offshore North West Java block and the West Seno field according to SKK Migas.
The prolific Attaka field was discovered by Unocal along with its partner, INPEX, in 1970 in the East Kalimantan offshore working area. The Attaka field is the first commercial offshore oil field in Kalimantan. At its peak, it produced 110,000 barrels of oil and 150 MMSCF of gas per day. After more than 50 years of production, its daily oil production today has declined to less than 5000 BOPD.
Pertamina Hulu Kalimantan Timur became the field operator in October 2018.
Producing around 5.3 billion SCF of gas daily in 2022, Indonesia utilized domestically 68% of its produced gas. The surplus was exported in the form of LNG and pipeline gas.
Here is the breakdown of the utilization of the produced gas.
Domestic Industrial use – 29%
LNG for export – 22%
LNG for domestic use – 9%
Fertilizers – 12.5%
Electricity generation – 11.5%
Exported Pipeline gas – 11%
LPG – 1.5%
The domestic need for gas is expected to grow in the form of gas and LNG as gas pipelines and FSRUs (floating storage and regasification unit) is being built.
Despite this, Indonesia will continue to have a surplus of gas in the coming years as the Tangguh LNG train #3 will go on stream by the end of 2023 and the Abadi LNG plant will be operating by the end of 2030, according to Rizal Fajar Muttaquien of SKK Migas.
PT Pertamina, the national oil company of Indonesia, is an integrated oil company and much more.
It is the largest oil and gas producer in Indonesia. Operating 27000 oil and gas wells in 65 oil and gas blocks and producing 566,000 barrels of oil and 2600 MMSCF of gas daily in 2022, Pertamina produces 68% and 34% of the total crude oil and natural gas respectively in Indonesia. Its total daily hydrocarbon production is equivalent to 967,000 BOEPD.
HISTORY OF PERTAMINA
Pertamina began as Perusahaan Minyak Nasional (Permina) on December 10, 1957. The 10 December 1957 date is celebrated as the birthdate of Pertamina.
In 1960 Permina became Perusahaan Negara Permina (PN Permina). It then acquired and managed all the oil and gas assets of BPM (Bataafsche Petroleum Maatschappij) in 1965.
Then PN Permina merged with Pertamin to became PN Pertamina (Perusahaan Negara Pertambangan Minyak dan Gas Bumi Negara) on 20 August 1968.
Finally, PN Pertamina became PT Pertamina, a limited company as it is today on 18 June 2003.
From the late 1960s through the 1990s Pertamina was in charge of all the production-sharing contracts issued to foreign oil companies.
Pertamina, with the status of PSO (Public Service Obligation) given in 1972, has the mandate to supply and distribute all the fuels needed in Indonesia.
COMPANY STRUCTURE
Currently, Pertamina conducts its operations under six sub-holding companies: • PT Pertamina Hulu Energi – Upstream oil and gas operation • PT Perusahaan Gas Negara – Gas supply and distribution • PT Kilang Pertamina International – Oil refining and petrochemicals • PT Pertamina Power Indonesia – Power generation and Renewable energy • PT Patra Niaga – Commercial and Trading • PT Pertamina International Shipping – Oil and gas shipping and marine logistics
PRESIDENTS OF PERTAMINA
Ibnu Sutowo is the first and the most notable president of Pertamina. During his tenure from 1968-1976, he oversaw all the PSC contracts signed by many international oil companies that created the oil boom in Indonesia from 1970-2000. He was given full authority by the then-president of Indonesia, Soeharto, to develop the oil and gas resources of Indonesia.
Here are the past and the current presidents of Pertamina.
Ibnu Sutowo (1968-1976).
Piet Haryono (1976-1981).
Joedo Soembono (1981-1984).
R. Ramli (1984-1988).
Faisal Abda’oe (1988-1996).
Soegijanto (1996-1998).
Martiono Hadianto (1998-2000).
Baihaki Hakim (2000-2003).
Ariffi Nawawi (2003-2004).
Widya Purnama (2004-2006).
Ari Soemarno (2006-2009).
Karen Agustiawan (2009-2014).
Dwi Soetjipto (2014-2017).
Elia Massa Manik (2017- 2018).
Nicke Widyawati (2018 – now).
Board of Directors and Executive Team
Here are the newly elected board of directors and the executive team of Pertamina announced during the annual general meeting of shareholders on January 31, 2024.
Board of Directors
Chairman – Basuki Tjahaja Purnama
Vice Chairman – Rosan P. Roeslani
Board member – Heru Pambudi
Board member – Rida Mulyana
Independent board member – Alexander Lay
Independent board member – Ahmad Fikri Assegaf
Independent board member – Iggi H. Achsien
Executive Team
President and CEO – Nicke Widyawati
Vice CEO – Wiko Migantoro
Chief of Risk Management – Ahmad Siddik Badruddin
Chief of Logistics and Infrastructure – Alfian Nasution
Chief of Finance – Emma Sri Martini
Chief of Human Resources – M. Erry Sugiharto
Chief of Business Support – Erry Widiastono
Chief of Portfolio Strategy and Business Development – Atep Salyadi Dariah Saputra
This post is adapted by Jamin Djuang – Chief Learning Officer of LDI Training
The Kamojang Power Station of Pertamina Geothermal Energy – Photo courtesy of PGE.
The Beginning
Indonesia is the second-largest geothermal energy producer in the world, after the US, with a total installed capacity of 2653 MW as of December 2024, according to ThinkGeoEnergy.
The story of geothermal energy in Indonesia began in 1918 when Dutchman JB Van Dijk noticed and reported the potential of geothermal energy in the Kamojang area of West Java.
Inspired by the successful geothermal development in Larderello in Italy, a Dutch company drilled five shallow wells between 60 and 128 meters deep from 1926 to 1927 in the Kamojang area. One of them, the well KMJ-3, was successful and is still producing steam today.
This discovery established the Kamojang area as having tremendous potential for geothermal energy development.
Subsequently, in 1974, Pertamina began exploring and assessing the geothermal resources in Kamojang in earnest with the cooperation of New Zealand.
Then in 1978, the first geothermal power station in Indonesia came into production at Kamojang with an installed capacity of 0.25 MW.
Today, the Kamojang power plant consists of 5 power stations with a total installed capacity of 235 MW, making it one of Indonesia’s biggest geothermal power plants.
Since the establishment of the Kamojang plant, many companies have started to develop geothermal resources in Java, Sumatra, and the Eastern part of Indonesia.
Here are the seven geothermal operators in Indonesia.
PERTAMINA GEOTHERMAL ENERGY
Pertamina Geothermal Energy is Indonesia’s first and most active geothermal company. It constructed the first geothermal plant in Indonesia, the Kamojang power plant in 1978 with the cooperation of New Zealand.
PGE operates and supplies steam to 21 geothermal power plants in six work areas, namely in Kamojang, Sibayak North Sumatra, Ulubelu, Lahendong, Lumut Balai South Sumatra, and Karaha West Java. The total installed capacity of the 22 power stations is 727 MW.
Besides these direct operations, PGE has joint operation contracts with several geothermal operators in the operation of their power plants with a total of 1205 MW installed capacity.
Pertamina Geothermal Energy became a public company on February 24, 2023. With the 594 million USD of fresh funds it received from the IPO, PGE plans to add 600 MW of installed capacity by 2029.
Here are the geothermal plants that PGE operates: • 235 MW Kamojang Units 1, 2, 3, 4, 5 in West Java (Note: Supplying steam to Units 1, 2, and 3 operated by PLN) • 120 MW Lahendong Units 1, 2, 3, 4, 5, 6 in Sulawesi • .5 MW Lahendong Binary in Sulawesi • 110 MW Ulubelu Units 1 and 2 in Lampung, Sumatra (Note: Supplying steam to PLN) • 110 MW Ulubelu Units 3 and 4 in Lampung, Sumatra • 110 MW Lumut Balai Unit 1 and Unit 2 in South Sumatra • 30 MW Karaha Bodas in West Java • 12 MW Sibayak Unit 1, 2, and 3 in North Sumatra
Upcoming Projects
Pertamina Geothermal Energy is intensifying its efforts to expand geothermal power generation capacity.
The company plans to add up to 215 MW of new capacity through the following projects:
– Lahendong Power Plant Units 7 and 8, each with a capacity of 20 MW, along with a 10 MW binary unit in North Sulawesi.
– Lumut Balai Units 3 and 4, each with a capacity of 55 MW, are located in South Sumatra.
– Ulubelu Extension 1 in the Gunung Tiga geothermal area in Lampung, which has a potential capacity of 55 MW.
These projects are targeted for completion by 2029.
Here are PGE’s other joint venture projects:
• PGE, Chevron, and Mubadala have agreed to conduct a joint study to explore the geothermal potential in Kotamobagu located in North Sulawesi.
• PGE and Chevron will spend 220 million USD to develop the Way Ratai geothermal work area in Lampung. The consortium aims to construct a 55-MW power plant by 2031.
STAR ENERGY GEOTHERMAL
Star Energy Geothermal was established in 2003. Its vision is to be the fastest-growing, most profitable, best-managed energy company in the region.
Star Energy, operating three geothermal power plants with a total installed capacity of 874 MW, is Indonesia’s largest geothermal energy producer.
Here are the three geothermal plants in which it operates. • Salak plant (337 MW) in West Java – Acquired from Chevron in 2017 • Darajat plant (270 MW) in West Java – Acquired from Chevron in 2017 • Wayang Windu (227 MW) in West Java – Acquired from Magma Nusantara Limited in 2004
Current Projects • Exploring the geothermal prospect in Gunung Hamiding, located in North Maluku. • Exploration in Sekincau in Lampung, Sumatera
Here are the subsidiary companies of Star Energy Geothermal: • Star Energy Geothermal Salak, Ltd. • Star Energy Geothermal (Wayang Windu) Limited| • Star Energy Geothermal Darajat II, Limited • PT Star Energy Geothermal Suoh Sekincau
PT GEO DIPA ENERGY
Geo Dipa Energy was founded in 2002 by the Indonesian government to construct and operate the Dieng and Patuha geothermal power plants.
Managing two geothermal plants with a combined capacity of 125 MW, Geo Dipa Energy’s vision is to be a reliable and trusted geothermal company.
Here are the two plants that Geo Dipa Energy operates: • 70 MW Dieng Unit 1 power plant located in Central Java. • 55 MW Patuha Unit 1 power plant located in West Java.
Current Projects • Dieng Unit 2 Development. Geodipa is drilling steam wells for the 55 MW Dieng Unit 2 power station project. • Patuha 55 MW Unit 2 Development. • Exploration in the Candradimuka work area. • Exploration in the Arjuno Welirang work area.
KS ORKA RENEWABLES PTE LTD
KS Orka Renewables, established in 2015, manages and operates 5 geothermal stations and 2 power stations in North Sumatera and Flores respectively.
Its newest power plant, completed in December 2024, is the 33-MW Sorik Marapi Unit 5 in North Sumatra. PT Sorik Marapi Geothermal Power, the plant operator, started the plant commercially on December 16, 2023.
Here are the power plants that KS Orka Renewables operates: • 220 MW Sorik Marapi geothermal plant in North Sumatra consisting of Units 1, 2, 3, 4, and 5 power stations. • 5-MW Sokoria Unit 1 and 3-MW Unit 2 geothermal plants in Flores.
Current Projects: • Exploration in the Samosir work area in North Sumatera
Here are the operating subsidiary companies of KS Orka Renewables:
PT Sorik Marapi Geothermal Power
PT Sokoria Geothermal Indonesia
PT Samosir Geothermal Power
PT SUPREME ENERGY
Supreme Energy was founded in 2007 under the leadership of Mr. Supramu Santosa, with Engie, Marubeni, and Tohoku Electric Company as joint venture partners. Its vision is to become the leading and most respected geothermal energy company, generating clean and sustainable electricity. Mr. Nisriyanto is the current President and CEO.
Supreme Energy operates three power stations in two work areas with a total installed capacity of 130 MW.
Here are the three power stations: • The 45.6 MW Unit 1 and 45.6 MW Unit 2 stations in the Rantau Dedap work area in South Sumatera. . Based on the PPA (Power Purchase Agreement) with PLN, Supreme Energy Rantau Dedap has the potential to double its energy output to 220 MW.
• The 85 MW Muara Laboh Unit 1 power plant in West Sumatera.
Current Projects • Exploration in the Rajabasa work area • Development of 75 MW Muara Laboh Unit 2 power station.
Here are the three subsidiary companies of Supreme Energy:
PT Supreme Energy Rantau Dedap
PT Supreme Energy Muara Laboh
PT Supreme Energy Rajabasa
SARULLA OPERATIONS LIMITED
Sarulla Operations Limited is a consortium consisting of Medco Power Indonesia, INPEX, Ormat Technologies, Itochu Corporation, and Kyushu Electric Power.
Sarulla Operations Limited was established in 2006 when PLN, the national power company of Indonesia, awarded the company to take over the development of the Sarulla geothermal project in North Sumatra.
The Sarulla geothermal resources, situated in North Sumatra, were first discovered by Unocal Geothermal. From 1993 to 1998, Unocal carried out extensive exploration in the Sarulla geothermal working area, drilling a total of 13 deep wells. This exploration confirmed the presence of 330 MW of commercial geothermal reserves, estimated to be viable for 30 years.
However, due to the Asian financial crisis in 1997, Unocal did not get the approval to build the power plants.
With a total investment of 1.7 billion USD, Sarulla Operation Limited completed the first power station in March 2017, the second station in October 2017, and the third station in March 2018.
Here are the three power stations that SOL operates: • 110 MW Silangkitang (SIL) Unit 1 • 110 MW Namora-I-Langit (NIL) Unit 1 • 110 MW Namora-I-Langit (NIL) Unit 2
PLN GAS AND GEOTHERMAL
PLN Gas and Geothermal is a subsidiary company of Perusahaan Listrik Negara (PLN), the national power company of Indonesia.
As the sole distributor of electricity in Indonesia, besides purchasing electricity from all independent geothermal operators, PLN also operates several geothermal power plants of its own.
Here are the geothermal plants which PLN operates: • 110 MW Ulubelu Unit 1 and Unit 2 – Steam supplied by Pertamina Geothermal Energy • Kamojang Unit 1 (30 MW), Unit 2 (55 MW), and Unit 3 (55 MW) – Steam supplied by Pertamina Geothermal Energy • 10 MW Ulumbu Unit 1,2,3,4 in Flores • 2.5 MW Mataloko in Flores
PLN has an ambitious plan to produce more geothermal power from its geothermal work areas. It is working further to develop the geothermal resources in Ulumbu and Mataloko. It has a plan to build 20 MW Ulumbu Unit 5 and two 10 MW power stations in Mataloko.
It is also currently looking for international and national investors to partner and collaborate to develop the following four geothermal projects: • 20 MW Tulehu in Central Maluku • 10 MW Atadel in East Nusa Tenggara • 10 MW Songa Wayaua in North Maluku • 20 MW Tangkuban Perahu in West Java
MEDCO CAHAYA GEOTHERMAL
Indonesia welcomes its newest geothermal power plant, the 35-MW Ijen geothermal power plant, which started commercial operations in February 2025 in East Java.
The Ijen power plant is developed and operated by Medco Cahaya Geothermal (MCG), which is a joint venture between Medco Power Indonesia and Ormat Technologies.
Medco Power is not new to geothermal energy. It has a stake in the big 330-MW Sarulla geothermal power plant operated by Sarulla Operations in North Sumatra.
With the entrance of MCG, Indonesia now has eight geothermal power plant operators.
Epilogue As Indonesia is eager to increase its electricity generation using renewable resources, and with its abundant geothermal resources in its backyard, we shall see more geothermal development in the future.
Jamin Djuang – Chief Learning Officer of LDI Training
Oil companies had immense roles in the geothermal development in Indonesia. They were the ones who kickstarted the geothermal industry in the country from 1970-2010.
Without their efforts and perseverance, Indonesia would probably not be the second-largest geothermal energy producer in the world after the USA today.
Here are the oil companies that played key roles in the early development of geothermal projects in Indonesia.
Pertamina with the cooperation of New Zealand completed the first Kamojang power station in 1982.
Amoseas, a joint venture of Chevron and Texaco, completed the first Darajat power station in 1994.
Unocal completed the first Salak power station in 1997.
Unocal started drilling deep geothermal wells in Sarulla in North Sumatra in 1993 and discovered the huge geothermal potential in the area. Unocal did not complete the project, however, due to the Asian financial crisis in 1997. The project was later taken over by Sarulla Operation Limited which finally completed the huge 330 MW Sarulla power plant in 2016.
Chevron took over operations and expansion of the Darajat and Salak power plants from Amoseas and Unocal years later. Chevron eventually sold the two projects to Star Energy.
The early rise of geothermal energy production in Indonesia is indeed due to the contribution of the oil companies that were operating in Indonesia.
The geothermal development in Indonesia is one of the collateral benefits that the country received when it massively opened up opportunities for international oil companies to explore and produce its oil and gas resources in the late 1960s when the production sharing contract scheme was introduced.
Anthony Menzies shared his comment that as in Indonesia, in the US, the geothermal industry was also pioneered by oil and gas companies, Phillips, Shell, Unocal, Chevron, etc. and they utilized their expertise in drilling, R&D, reservoir engineering and production to develop their geothermal assets and minimize development costs.
The photo above shows the 377 MW Salak geothermal plant built by Unocal – The biggest geothermal plant in Indonesia and one of the largest in the world. It is now operated by Star Energy.
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 NAME
OIL OR GAS
OPERATOR
Reentry TDE C-1X LSW
Gas
Pertamina Hulu Mahakam
MPT-1X
Gas
Pertamina Hulu Mahakam
Camelia – 001
Gas
Pertamina EP
Kenanga – 001
Gas
Pertamina EP
SGET – 001
Oil and gas
Pertamina EP
SA S-1
Oil and gas
Sele Raya Belida
GASOP D South – 1
Gas
Sele Raya Belida
JTB – 2X
Gas
PHE Ogan Komering
Flamboyan – 1X
Gas
Medco
Timpan – 1
Gas
Harbour Energy, Mubadala, BP
NSO – R2
Oil and gas
PHE – North Sumatra Offshore
NSO – S2
Gas
PHE – North Sumatra Offshore
Anambas – 2X
Gas
KUFPEC
Nuri – 1X
Oil
Bumi Siak Pusako (BSP)
SRT – 1X
Oil and gas
PHE Jambi Merang
Wilela – 001
Gas
Pertamina EP
GQX – 1
Oil and gas
PHE – Offshore North West Java
Bajakah – 1
Oil and gas
Pertamina EP
Kolibri – 001
Gas
Pertamina EP
Phoenix – 1X
Gas
Pertamina Hulu Sanga Sanga
Markisa – 001
Gas
Pertamina EP
Kembo – 001
Oil and gas
Pertamina EP
Here are the locations of the exploration wells.
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.
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 OPERATORS
AVERAGE BPD IN 2022
ExxonMobil Cepu Ltd
165,906
Pertamina Hulu Rokan
159,254
Pertamina EP
70,157
Pertamina Hulu Energi ONWJ
27,584
Pertamina Hulu Mahakam
25,091
Pertamina Hulu Energi OSES
19,638
PetroChina International Jabung Ltd
15,610
Medco E&P Natuna
10,255
Pertamina Hulu Sanga Sanga
9374
Pertamina Hulu Kalimantan Timur
9013
Bumi Sakti Pusako (BSP)
8240
Saka indonesia Pangkah Ltd
7624
JOB Pertamina Medco Tomori Sulawesi
7839
Petronas Carigali Ketapang Ltd
7579
Husky-CNOOC Madura Ltd
6421
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.
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 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.
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
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”.
