The Amazing Rise of Medco Energi

The Belanak FPSO

Medco Energy International is the first publicly owned oil company in Indonesia.

Medco is celebrating more than forty years of presence and continuing successes as one of the leading energy companies in Indonesia and Southeast Asia.

Medco Energi International became a public company in 1994, and today it operates in eight countries.

It has interests in oil and gas exploration and production, geothermal power generation, gas distribution and trading, and mining.

The year 2022 is a wonderful year for Medco Energy. It booked net profits of 531 million USD in 2022 which is more than 10 times higher than the US$ 47 million it made in 2021. The company produced 163 million barrels of oil equivalent (BOE) in 2022, a 73% increase over the previous year.

The Beginning of Medco

Medco Energi has come a long way in a short time since it started as an oil drilling service company in 1980, Meta Epsi Pribumi Drilling Company (MEDCO).

Founded by Mr. Arifin Panigoro, Medco Energi was a visionary and a trailblazer ever since its beginning.

The Acquisition of Stanvac Indonesia

The first breaks that made Medco became big and successful were the acquisition of Stanvac’s oil and gas assets in South Sumatera in 1995, and the following discovery of the big oil fields in Kaji and Semoga in the Rimau Block, in South Sumatera.

Stanvac Indonesia, set up by Standard Oil of New Jersey in 1912, was one of the oldest and biggest oil companies in Indonesia during the Dutch colonial era.  

The Acquisition of ConocoPhillip’s Interest in West Natuna Sea Block B PSC

Medco Energi further expanded in 2016 when it purchased ConocoPhillips’s 40% interest in the West Natuna Sea Block B and took over the operatorship of the block.

This acquisition added substantial gas and liquids reserves and increased Medco Energi’s daily production by over 35%.

The block is in approximately 300 feet of water and had 11 offshore platforms, four producing subsea fields, and one FPSO – the Belanak FPSO – in addition to two dedicated floating storage and offloading vessels.

The Belanak FPSO was described as one of the most complex FPSO in the world. It was the first offshore liquefied petroleum gas (LPG) facility on a floating vessel in the Asia Pacific region when it was commissioned in 2004.

The fields include the Belanak field, South Belut field, Hiu field, Kerisi field, North Belut field and Bawal field.

The produced natural gas is sold to Singapore and Malaysia through a 654 KM long 28 inch gas pipeline.

Medco Energi also assumed the operatorship of the Onshore Receiving Facility in Singapore following the acquisition.

Acquisition of Ophir Energy

Medco Energi Internasional continued to expand by acquiring Ophir Energy, a London-based independent in 2019.

The acquisition of Ophir Energy increased Medco Energi’s daily oil and gas production by 29% to 110,000 BOE per day.

By taking over the operatorship of Ophir Energy’s offshore Bualuang field in Thailand, Medco Energi became a leading regional oil and gas player in South East Asia.

Acquisition of Corridor PSC and Transasia Pipeline

On March 3, 2022, Medco Energi acquired the entire remaining assets of ConocoPhillips in Indonesia..

Through this acquisition, Medco Energi is now the operator of the Corridor block with 54% interest and has 35% ownership of Transasia Pipeline Company.

The Corridor PSC has two producing oil fields and seven producing gas fields located onshore South Sumatra, Indonesia, adjacent to MedcoEnergi’s existing operations in South Sumatra. The Corridor is the second-largest gas-producing block in Indonesia.

Through Transasia, MedcoEnergi now owns a minority interest in the gas pipeline network supplying Central Sumatera, Batam, and Singapore customers.

Epilogue

With this latest acquisition, Medco Energi is now one of the largest oil and gas operators in Indonesia.

Besides acquiring producing assets, Medco Energi is also active in exploring new oil and gas reserves.

Its 2020 exploration drilling campaign in the South Natuna Sea Block B was 100% successful. It tested hydrocarbon in all the four exploration wells it drilled. The wells are Bronang-2, Kaci-2, Terubuk-5, and West Belut-1.

Medco Energi is planning to develop these fields.

As Medco Energi celebrates its more than 40 years of progress, with its solid management team, it certainly will continue to march toward an even brighter future.

Top Management Team of Medco Energi

Here is the top management team of Medco Energi.

Muhammad Lutfi – President Commissioner

Hilmi Panigoro – President Director

Roberto Lorato – Chief Executive Officer

Anthony R Mathias – Chief Financial Officer

Ronald Gunawan – Chief Operating Officer

Amri Siahaan – Chief Human Capital and Business Support Officer

Myrta Sri Utami – VP Corporate Planning & IR

Siendy K Wisandana – Head of Legal Counsel and Secretary

As a final note, Dr. Arifin Panigoro, the man who started it all and the founder of Medco group of companies died on 27 February 2022 at age of 76.

Written by Jamin Djuang – Chief Learning Officer of LDI Training and author of the published book The Story of Oil and Gas: How Oil and Gas are Explored, Drilled and Produced.

The Job of A Mudlogger

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

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

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

Sample Catchers

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

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

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

 

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A shale shaker

 

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

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

 

Mudloggers and Data Engineers (DE)

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

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

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

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

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

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

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

 

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A mudlogging unit

 

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

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

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

Sensors

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

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

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

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A drilling parameter screen

 

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

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

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

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

inside a mudlogging unit - amanda
Inside a mudlogging unit

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

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

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

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

 

 

The World Top 10 Oil Producers

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Offshore oil and gas production and processing platforms and facility.

 

In 2018, daily world oil production amounts to around 92 million barrels per day, increasing slightly 0.7% from previous year.

Here are the world top ten oil producers according to the US Energy Information Administration (EIA) in 2017:

  1. USA – 15.6 Million barrels of oil per day
  2. Saudi Arabia – 12.1 Million BOPD
  3. Russia – 11.2 Million BOPD
  4. Canada – 5.0 Million BOPD
  5. China – 4.8 Million BOPD
  6. Iran – 4.7 Million BOPD
  7. Iraq – 4.5 Million BOPD
  8. UAE – 3.7 Million BOPD
  9. Brazil – 3.4 Million BOPD
  10. Kuwait – 2.9 Million BOPD

The USA is the largest oil producer in the world in 2017. The production of crude oil in the USA is expected to increase into 2019. The USA is also the world’s largest consumer of oil. Its daily oil consumption in 2019 is projected to increase by 340,000 barrels to 20.65 million barrels, according to EIA.

EIA reported on 21 December 2018 United States produced a total of 16.3 million barrels per day of crude oil and natural gas liquids in November 2018.  This total production consists of 11.7 million BPD of crude oil and 4.6 BPD of natural gas liquids or NGL.

Saudi Arabia, on the other hand, is the largest oil exporting country. As the most well-known and influential oil producer, it has 260 billion barrels of oil reserves, which is about 22% of the world’s oil reserves.

The Top Three Unconventional Oil and Gas Resources

Unconventional oil and gas resources are resources where the oil and gas are difficult to recover or produce due to either the very low permeability of the formation or the very low mobility of the hydrocarbons. Special techniques and processes are required to recover these types of resources.

The three common types of unconventional hydrocarbon resources are:

  1. Oil sands.
  2. Shale oil and shale gas.
  3. Coal-bed Methane.

Oil Sands

The world’s largest oil sand deposit is the Athabasca oil sands located in Alberta, Canada. Oil sands are a mixture of semi-solid bitumen or asphalt and sand, and they are buried not far from the earth’s surface. Commercial production of the Athabasca oil sands began in 1967 and the current production is at around two million BOPD. Many major oil companies are involved in the production of these oil sands.

Two methods are used to recover the oil from the oil sands. They are open-pit mining and the SAGD method.

The open-pit mining method is commonly used to extract the oil from oil sands located near the earth’s surface. After the tar sand is mined, it is mixed with hot water and agitated to form a slurry. The released bitumen droplets will float to the surface with the help of the tiny air bubbles which attach to the bitumen droplets. The bitumen will then be skimmed off and further processed to remove the remaining water and solids. Lastly, the bitumen will be upgraded to synthetic crude oil. About 75% of the bitumen can be extracted from the tar sands.

For tar sands located at a deeper depth, in-situ production methods are used, such as steam injection, fire flooding, and chemical injection. A popular steam injection method is the SAGD method. In SAGD, steam-assisted gravity drainage, a pair of horizontal wells are drilled into the oil sand, one at the bottom of the formation and another about 5 meters above it. High-pressure steam is injected into the sand from the upper well to heat the heavy oil and thus reduce its viscosity. With the increase in mobility, the oil drains into the lower well where it is pumped to the surface. SAGD is the preferred method for extracting the oil sands due to environmental concerns.

Shale Oil and Shale Gas

Another currently popular unconventional hydrocarbon resource is shale oil and shale gas. Shale oil is oil that is trapped inside the tight shale. Shale is a hard sedimentary rock

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An oil field and sucker Rod pumps

composed of clay that is rich in organic materials. Since tight shale has very low permeability, the hydraulic fracturing method is used to extract the oil. In hydraulic fracturing, a large quantity of viscous fluid-carrying sand is pumped into the well under high pressure to fracture the shale, creating pathways and highways for the oil to flow out of the shale and into the wellbore.

Most shale oil production takes place in the US and the daily production of shale oil reaches six million BOPD in 2017. A large quantity of gas is also produced from shale. According to the US Energy Information Agency (EIA), gas production from shale in the US in 2016 was 15.8 trillion cubic feet (TCF).

The most well-known and top shale oil plays in the US are the Permian Basin and Eagle Ford Shale in Texas, and Bakken Shale in North Dakota.

Coal Bed Methane

Coalbed methane (CBM) is an unconventional resource of methane gas. It is being produced successfully in some parts of the world, notably in Australia and Canada. Since coal is formed from organic materials, methane gas (CH4) is generated during the formation of coal. The generated methane is adsorbed in the coal matrix, fractures and coal seams called cleats. Cleats are horizontal and vertical fractures formed naturally in coal.  

Wells are needed to produce the trapped methane gas. Since underground coal is usually saturated with water, methane is extracted by first removing the water from the coal by pumping out the water. As the water is pumped out from the well, the coal pore pressure will decrease causing the adsorbed gas to be liberated from the coal and then flow to the wellbore. Due to the low permeability of the coal matrix, the coal must have a sufficient network of fractures and cleats to produce the methane gas at economic production rates.

This article was written by Jamin Djuang, a published author of “The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced” for readers who have not seen an oil field.

 

The 10 Giant Offshore Oil and Gas Fields in Indonesia

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A drilling rig on top of a fixed offshore production platform. The drilling operation was supported by a floating platform.

Since 1966 when Indonesia began offering production sharing contracts (PSC) for international companies to explore and produce oil and gas in Indonesia, many giant and super-giant oil and gas fields were discovered.

Giant fields are those with estimated ultimate recoverable reserves (EUR) of 500 million barrels of oil or gas equivalent (MMBOE) and super giant oil fields are those holding an equivalent of 5.5 billion barrels of oil reserves.

Here are the ten giant offshore oil and gas fields in Indonesia discovered between 1966 and 2000.

1. Abadi Field

Abadi is a giant gas field discovered by Inpex in 2000 in the Masela contract area in the Arafura Sea. The Abadi field has an estimated ultimate recovery (EUR) of 768 MMBOE and it is located 93 miles offshore from the province of Maluku in the eastern part of Indonesia.

Originally the field would be developed using a subsea production system and a floating LNG (FLNG) facility. The plan now is to develop the field based on an onshore LNG development concept.

Inpex in partnership with Royal Dutch Shell is currently conducting preliminary front-end engineering design (Pre-FEED) studies for the Abadi field development based on an onshore concept. The LNG project will produce 9.5 MM tons of LNG annually.

When developed, the Abadi field may become the biggest deepwater gas project in Indonesia. It is expected to produce more than 1 billion SCF of gas per day and 20,000 barrels of condensate per day for 24 years.

2. Gula Field

The Gula field is an offshore gas field discovered by Unocal in its Ganal production sharing contract area located in the Kalimantan strait in 2000. With an estimated ultimate recovery (EUR) of 545 MMBOE, it is a giant gas field.

The Gula field, along with the Gendalo discovery and the Gada discovery, is one of the many discoveries made by Unocal in the deep-water area between Kalimantan and Sulawesi. These discoveries confirm that the Central Delta play contains world-class gas resources.

The Gula field is currently an undeveloped discovered resource.

3. Ubadari Field

Ubadari is a giant offshore gas field discovered in 1997. The Ubadari field has an EUR of 500 MMBOE and it is located at Bintuni Bay in West Irian province.

The Ubadari field will supply its gas to the Tangguh LNG plant when the Tangguh LNG Train-3 project is completed in 2020. The Tangguh expansion aims at meeting the ever-increasing demand for energy in Indonesia and accelerating the development of West Irian.

PLN, Indonesia’s electricity company, has signed a sales and purchase agreement to buy up to 1.5 million tons of LNG produced by Tangguh LNG plant annually.

Tangguh LNG plant is scheduled to process the gas produced from the six gas fields located at Bintuni Bay: Vorwata, Wiriagar Deep, Ofaweri, Roabiba, Ubadari, and Wos.

4. Vorwata Field

Vorwata is an offshore giant gas field located in Bintuni Bay in West Irian Province. The Vorwata field, with an EUR of 1833 MMBOE, was discovered by ARCO in the Berau block in 1997. BP became the operator of the Vorwata field after it acquired ARCO.

Gas production from the Vorwata field started in 2009. The field is capable of producing more than 1 BCF of gas per day and the gas is processed into LNG by the Tangguh LNG plant.

5. West Seno Field

The West Seno field is a deepwater oil field discovered by Unocal in 1996. Having an EUR of 553 MMBOE, it is a giant oil field and is currently operated by Chevron.

Lying in water depths of 2,400 to 3,400 feet, the West Seno field is Indonesia’s first deepwater development. It lies in the Makassar Strait PSC off Kalimantan on the continental slope of the northern Mahakam Delta.

The oil is produced using a tension leg platform and a floating production unit, tied back by two export pipelines to onshore infrastructure.

6. Peciko Field

Peciko is a gas field located offshore in the Mahakam Delta in East Kalimantan. The field was discovered by Total with INPEX as its partner in 1991. The Peciko is a giant gas field having an EUR of 1180 MMBOE.

Of all the producing fields in the Mahakam River delta, the Peciko field is unique in that its reservoir trap is both structural and stratigraphic.

The Peciko wells are highly productive having an average well productivity of 80 MMSCF of gas per day. Total daily gas production reached 1700 MMSCFD during its peak in 2005-2006. A substantial quantity of condensate is being produced along with the gas.

7. Tunu Field

The Tunu field is a supergiant gas field discovered by Total along with Inpex as its partner in 1977. It is located in the shallow waters along the outer limits of the delta offshore Mahakam Block in East Kalimantan. It has an EUR of 4378 MMBOE.

Started in 1978, the Tunu field produces gas and condensate having negligible CO2 or H2S, with the main productive reservoirs lying at depths from 2,200 to 4,900 meters.

Developing the large Tunu field is challenging and producing the gas requires drilling a large number of wells. The field has a large surface area of 20 Km wide and 75 Km long and it is located at the wetland of Mahakam swamp.

8. East Natuna Field

The offshore East Natuna gas field was discovered by AGIP in 1970. It is located 140 miles northeast of the Natuna Islands, Indonesia’s northernmost territory. It is a super-giant gas field with estimated recoverable reserves of 46 trillion cubic feet (TCF) of gas.

There were serious studies done and attempts made by Exxon-Mobil and Pertamina to develop this field.

The field is currently undeveloped due to its very high CO2 content of 71%. To produce the gas will require removing the CO2 from the gas and injecting it back into the reservoir. Production can be commercially viable when the price of oil is above $100 per barrel.

9. Attaka Field

The Attaka field is a giant oil and gas field discovered by Unocal in partnership with Inpex in 1970.   Chevron became the field operator after it acquired Unocal in 2005. Having an EUR of 1000 MMBOE, the Attaka field is located 12 miles from the shore of East Kalimantan.

The huge Attaka reservoir, formed in the very prolific Kutei basin, has an areal closure of 8000 acres. Due to its large areal extent, originally the oil and gas were produced from more than 100 wells located in 6 remote wellhead platforms.

Ten years later, five subsea wells were completed in 1981-1984 to produce the untapped oil accumulation in areas out of reach of the existing remote platforms. These are the first subsea completions in Indonesia.

Attaka field daily oil production was 110,000 BOPD at its peak and gas production was 150 MMSCFPD. Now the Attaka field is quite depleted.

10. Ardjuna Field

The Ardjuna Field is a giant oil field having an EUR of 698 MMBOE. This is the first offshore giant field discovered since the birth of the Indonesian PSC system in 1966.

The Ardjuna field was discovered by ARCO in the Offshore North West Java (ONWJ) production sharing contract area in 1969. Subsequently, it was operated by BP when it acquired ARCO in 2000. Now the field is operated by Pertamina Hulu Energy ONWJ Ltd.

Interesting facts about the Ardjuna field include the drilling of the first horizontal well in Indonesia in 1985 and supplying gas to PLN’s power plant in Muara Karang in Jakarta in 1993.

Pertamina’s refinery in Cilacap began using crude oil from the Ardjuna field in 1986.

This article was written by Jamin Djuang, a published author of “The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced” for readers who have not seen an oil field.

Digital Rock Physics – Core Analysis Using Digital Technology

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Offshore oil and gas processing platform,

In the last decade, there has been an important breakthrough in how petroleum engineers and geoscientists obtained oil and gas reservoir rock properties.

Traditionally, reservoir rock properties or petrophysical properties such as porosity, pore size distribution, effective and relative permeability, capillary pressure, water saturation and other reservoir parameters are determined from Special Core Analysis (SCAL), electric logs and well pressure transient tests. In recent years, a new method in determining rock properties using Digital Rock Physics (DRP) has gained serious attention from petroleum engineers, petro-physicists and geoscientists.

What is digital rock physics? Digital rock physics is also referred to as digital core analysis. In this measurement method, high-resolution digital images of the rock pores and mineral grains of selected reservoir core samples are made and analyzed. These images are usually 3D digital X-ray micro-tomographic images. The rock properties are then determined using numerical simulation at the pore scale.

The significant benefit of this new DRP technology is now a large number of complex reservoir parameters can be determined faster and more accurately than the traditional laboratory measurements or well testing methods.

Using the DRP technology to determine the rock properties, oil and gas companies can now analyze their reservoir capacity and performance more accurately and sooner during the field evaluation and development phase. This, in turn, allows them to develop and manage their reservoirs more efficiently and economically.

Source – Digital Rock Physics for Fast and Accurate Special Core Analysis in Carbonates – A Chapter in New Technologies in the Oil and Gas Industry – By  Mohammed Zubair Kalam

Gas Handling, Conditioning and Processing

This gas handling, conditioning and processing course is designed and presented by Dr Maurice Stewart to teach you how to design, select, specify, install, test and trouble-shoot your gas processing facilities.

This gas handling, conditioning and processing course has been attended by thousands of oil and gas professionals since Dr Maurice Stewart began teaching it more than 20 years ago. Dr Stewart is a co-author of a widely acclaimed “Surface Production Operations: Design of Gas Handling Facilities” along with Ken Arnold.

By attending this course, participants will:

1. Know the important parameters in designing, selecting, installing, operating and trouble-shooting gas handling, conditioning and processing facilities.
2. Understand the uncertainties and assumptions inherent in designing and operating the equipment in these systems and the limitations, advantages and disadvantages associated with their use.
3. Learn how to size, select, specify, operate, maintain, test and trouble-shoot surface equipment used with the handling, conditioning and processing of natural gas and associated liquids such as separators, heat exchangers, absorption and fractionation systems, dehydration systems, refrigeration, low temperature separation units, JT plants and compression systems.
4. Know how to evaluate and choose the correct process for a given situation.

Course Content

In this 5-day course, Dr Maurice Stewart will cover the following topics:
• Fluid properties, basic gas laws and phase behaviour
• Well Configurations, surface safety systems (SSS) and emergency support systems (ESS)
• Gas Processing systems, selection and planning
• Water-hydrocarbon phase behaviour, hydrate formation prevention and inhibition
• Heat transfer theory and process heat duty
• Heat exchangers: configurations, selection and sizing
• Gas-liquid separation and factors affecting separation
• Types of separators and scrubbers, and their construction
• Gas-liquid separators and sizing
• Liquid-liquid separators and sizing
• Three phase separator sizing
• Pressure vessels: the internals, mechanical design and safety factors
• Separator operating problems and practical solutions
• Gas compression theory, compression ratio and number of stages
• Compressor selection: centrifugal compressors vs. reciprocating compressors
• Vapor recovery units, screw compressors and vane compressors
• Compression station design and safety systems
• Performance curves for reciprocating compressors
• Absorption process and absorbers
• Adsorption process and adsorbers
• Glycol gas dehydration unit design and operation
• Glycol unit operating variables and trouble shooting
• Glycol selection and glycol regeneration
• Acid gas sweetening processes and selection
• Fractionation, refrigeration plants, expander plants and J-T plants
• Process control and safety systems

Course Materials

Participants will receive the following course materials:
1. The 3rd Edition of Volume 2 of the widely acclaimed “Surface Production Operations: Design of Gas Handling Facilities” written by Ken Arnold and Dr Maurice Stewart. This textbook continues to be the standard for industry and has been used by thousands since its first printing over fifteen years ago.
2. A comprehensive set of lecture notes for after course reading and reference
3. An extensive set of practical in-class “case study” exercises developed by Dr Stewart that will be used to emphasize the design and “trouble-shooting” pitfalls often encountered in the industry.

Who Should Attend

• Facility engineers, production engineers, design and construction engineers, team leaders, operations engineers, maintenance team leaders/engineers and other personnel who are or will be responsible for the designing, selecting, sizing, specifying, installing, testing, operating and maintaining gas handling facilities, gas plant facilities and gas pipelines.
• Experienced professionals who want to review or broaden their understanding of gas handling, conditioning and processing facilities and gas pipeline operation and maintenance.
• Professionals with little to moderate experience with the handling or processing of natural gas and associated liquids.

If you like to receive a pdf file of this course outline, please contact us.

Registration Information

Course date: November 25-29, 2019
Location: Singapore
Tuition: US$4500

Registration Form

If you or your people want to attend this course, please register HERE.

Contact information
Email: lditrain@singnet.com.sg
Website: https://oilandgascourses.org

About Dr. Maurice Stewart

Maurice Stewart - LDI Training Dr. Maurice Stewart, PE, CSP, is a Registered Professional Engineer and Certified Safety Professional with over 40 years of experience in international consulting, trouble-shooting oil, water and gas processing facilities; and leading safety audits, hazards reviews and risk assessments.

He is internationally respected for his teaching excellence and series of widely acclaimed textbooks in the areas of designing, selecting, specifying, installing, operating and troubleshooting:

  • Oil and water handling facilities
  • Gas handling, conditioning and processing facilities
  • Facility piping and pipeline systems
  • Gas dehydration and sweetening facilities
  • Pumps, compressors and drivers
  • Instrumentation, process control and safety systems
  • Oil and gas measuring and metering systems

Dr. Stewart is the author of several new textbooks related to oil and gas processing facilities; and he is one of the co-authors of the SPE Petroleum Engineering Handbook.  He has authored and co-authored over 90 technical papers and contributed to numerous conferences as a keynote speaker. Dr. Stewart has taught over 60,000 professionals from more than 100 oil and gas related companies in 90 countries.

Dr. Stewart serves on numerous international committees responsible for developing or revising industry Codes, Standards and Recommended Practices for such organizations as ANSI, API, ASME, ISA, NACE and SPE. He is currently serving on the following American Petroleum Institute (API) committees: API RP 14C, RP 14E, RP 14F, RP 14G, RP 14J, RP 500 and RP 75. He has developed and taught worldwide short courses for API related to Surface Production Operations. In 1985, he received the National Society of Professional Engineers “Engineer-of-the-year” award.

Dr. Maurice Stewart holds a BS in Mechanical Engineering from Louisiana State University and MS degrees in Mechanical, Civil (Structural Option) and Petroleum Engineering from Tulane University and a PhD in Petroleum Engineering from Tulane University.  Dr. Stewart served as a Professor of Petroleum Engineering at Tulane University and Louisiana State University.

Here are the most frequently requested Dr. Maurice Stewart courses:

  • Oil and water handling facilities
  • Gas handling, conditioning and processing
  • Production safety systems
  • The new API RP 14C and API RP 17V
  • Plant piping and pipeline systems
  • Oil and gas project management
  • Pumps, compressors and drivers

Here are his upcoming courses – Featured Oil and Geothermal Courses

If you are interested in having an inhouse course with Dr. Maurice Stewart, please contact LDI Training at LDITrain@singnet.com.sg.

Production Safety Systems

A 5-day course by Dr. Maurice Stewart incorporating the new 2017 8th Edition of API RP 14C, the new API RP 17V 1st Edition, API RP 14J, API RP 500/505, API RP 520/521/2000, IEC 61508-2 and IEC 61508-3.

This intense Production Safety Systems course presents a systematization of proven practices for providing a safety system for onshore and offshore production facilities. Thousands of oil and gas professionals have attended this course since it was offered by Dr. Maurice Stewart more than 20 years ago.

This production safety systems course has been updated to reflect the changes provided in the new API RP 14C and the API RP 17V. In this course, you will learn the latest concepts, methods and practices that will make your facility operationally safe.

What You’ll Learn

• Provisions for designing, installing and testing both safety and non-marine emergency support systems (ESSs) on both onshore and offshore production facilities.
• Concepts of a facility safety system and outline production methods and requirements of the system.
• Guidance on how safety analysis methods can be used to determine safety requirements to protect common process components from the surface wellhead and/or topside boarding valve and for subsea systems including all process components from the wellhead and surface controlled subsurface safety valve (SCSSV) to upstream of the boarding shutdown valve. (Note: The shutdown valve is within the scope of API RP 17V for gas injection, water injection, gas lift systems and chemical injections.)
• The importance of “Safety Concept,” “Safety Reviews,” and “EB-HAZOPs.”
• A method to document and verify process safety system functions, i.e., safety analysis function evaluation (SAFE chart).
• Design guidance for ancillary systems such as pneumatic supply systems and liquid containment systems.
• A uniform method of identifying and symbolizing safety devices.
• Procedures for testing common safety devices with recommendations for test data and acceptable test tolerances.
• The Principles of Safe Facility Design and Operation, specifically, how to Contain Hydrocarbons, Prevent Ignition, Prevent Fire Escalation and Provide Personnel Protection and Escape.
• The Principles of Plant Layout Partitioning and how to partition a plant into Fire Zones, Restricted Areas and Impacted Areas thereby minimizing the Risk to Radiation, Explosion, Noise and Toxicity.
• How to determine Electrical Hazardous (Classified) Locations and determine what Electrical Equipment should be installed in these locations,
• The purpose of Surface Safety Systems, specifically, the Emergency Shut-down System, Emergency Depressurization System, Fire and Gas Detection Systems and High Integrity Protection Systems,
• The Objectives, Types, Location and Placement of Fire and Gas Detection Systems.
• The Objectives, Types and Performance of Active and Passive Fire Protection Systems.
• The Function, Types, Selection and layout of Vent, Flare and Relief Systems to minimize the effects of Radiation, Flammable Gas Dispersion and Toxic Gas Dispersion.
• The function and design considerations of Liquid Drainage Systems
• How to determine piping “spec breaks”.
• How to evaluate workplace and operating/maintenance procedures for “hidden” hazards.
• How to effectively design facilities and work areas to reduce human errors and improve performance.

Course Content

• Principles of safe facility design
• Ignition prevention
• Fire escalation prevention
• Personnel protection and escape
• Installation layout
• Electrical installations in hazardous (classified) areas
• Safety systems
• Pressure ratings and Specification breaks
• High Integrity Pressure Protection Systems (HIPPS)
• Safety system and ESS bypassing
• Onshore gathering station safety systems
• Fire and gas detection systems
• Active and passive fire protection
• Relief, vent and flare systems
• Liquid drainage systems
• Electrical Area Classification

Who Should Attend

This workshop is specifically targeted for professionals and engineers who are involved in safety or production operations and who want to:

1. Develop a better understanding of the effectiveness of existing Production Safety System initiatives at existing oil and gas facilities.
2. Appreciate the main steps contemplated in the Safe Design of a plant or facility,
3. Better understand the scope and functioning of the various safety related equipment installed onshore, offshore and subsea.
4. Review or broaden their understanding of how to conduct a safety analysis, Experience-Based HAZOP and how to install electrical equipment in hazardous (Classified) locations.
5. Other professionals who want to develop a better understanding of how to conduct a Safety Analysis, EB-HAZOPs and install electrical equipment in hazardous (Classified) locations.

Course Materials

• Each participant will receive a comprehensive set of worksheets and checklists to aid them in conducting a safety analysis
• Each participant will receive a comprehensive set of lecture notes for after course reading and reference
• An extensive set of practical in-class “case study” exercises specially designed by Dr. Maurice Stewart that emphasizes the design and “trouble-shooting” pitfalls often encountered in the industry.

If you like to receive a pdf file of this course outline, please contact us.

Registration Information

Course date : December 10-14, 2018
Location : Singapore
Tuition : US$4500

Registration Form

If you or your people want to attend this course, please register HERE.

Contact information

LDI Training Pte Ltd
369 Holland Road #02-04
Singapore 278640

Email : lditrain@singnet.com.sg
Website : https://oilandgascourses.org

The New API 2017 RP 14C and API RP 17V

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In 2017, API published the new 8th Edition of API RP 14C and created the new 1st Edition of API 17V for subsea applications.

Here are the major modifications of API RP 14C and the new guidelines provided in API RP 17V:

1. The API RP 14C, new 8th Edition “Analysis, Design, Installation, and Testing of Safety Systems for Offshore Production Facilities” was developed in coordination with the new First Edition of API RP 17V “Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Subsea Applications”.

2. Changes in safety system technology.

3. Additional guidance for facility safety systems as they have become larger, more complex and moved into deeper water.

4. Added requirements include an extensive emphasis on the performing of hazards analysis due to increased flow rates, pressures, temperatures, and water depth.

5. Better alignment with API Standard 521, “Pressure-relieving and Depressuring Systems”.

6. Additional requirements for pumps and compressors greater than 1000 HP and reference to API 670.

7. Additional requirements to protect against backflow and settle-out pressures.

8. New address on low-temperature hazards.

9. Enhancements on open deck Fire and Gas detection placement and sensor type.

10. Extensive emphasis on performing hazards analysis to include the introduction of the Prevention vs. Mitigation concepts.

11. Additional annex to cover topside High-Intensity Pressure Protection Systems (HIPPS).

12. Additional annex to cover Safety System By-passing.

13. Additional annex to cover Logic Solvers.

14. Additional annex to cover Remote Operation.

Since the API RP 14C and API RP 17V are critically important for the safety of your offshore and subsea facilities, please share this information with your company’s managers, supervisors, engineers and safety personnel who need to:

1. Develop a better understanding of the modifications of the 2017 edition of API RP 14C and the newly created API RP 17V

2. Appreciate the main steps contemplated in the Safe Design of onshore, offshore and subsea applications

3. Better understand the scope and functioning of the various safety-related equipment installed onshore, offshore and subsea.

If you want to understand the new API RP 14C and API RP17V to keep your production facilities safe, Dr. Maurice Stewart conducts a 5-day course – Production Safety Systems – that incorporates the new API RP 14C and API RP 17V.

This article is written by Dr. Maurice Stewart.

For more information about the course, please contact LDITrain@singnet.com.sg

10 Interesting Facts About The Super-Giant Oil Field of Attaka

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Attaka central platforms from left to right: Wellhead platform, Central Processing Platform, Compression Platform, and Quarter Platform

The Attaka Field Discovery

Attaka field, a giant offshore oil field located 12 miles from the shore of East Kalimantan in Indonesia was discovered by Union Oil of California (UNOCAL) in August 1970. This giant oil field having 1023 MMBOE of recoverable reserves is the first commercial oil field discovered in offshore Kalimantan.

General Soeharto, the president of Indonesia at that time, inaugurated the Attaka field and the Santan terminal on 22 January 1973.

Santan terminal is the onshore complex where the crude oil from the Attaka field is processed and stored before it is exported by oil tankers. Santan terminal is also where the produced gas is processed before it is sent to Badak LNG for liquefaction.

Unocal along with its 50-50 partner, Inpex, operated the Attaka field until it was acquired by Chevron in August 2005.  Later on, Pertamina Hulu Kalimantan Timur assumed the operatorship of the field on 25 October 2018 when the production sharing contract expired.

Interesting Facts About the Attaka Field

  1. Two years after its discovery, the Attaka field started producing oil in November 1972, making it the first offshore field in Kalimantan.
  2. Following the first discovery well, the Attaka Well 1A, seven appraisal wells were drilled to assess to size and potential of the hydrocarbon accumulation.
  3. The huge Attaka reservoir, formed in the very prolific Kutei basin, is a faulted anticline. Its areal extent of oil accumulation is nearly 10 square miles. Attaka field is one of five giant oil fields discovered in the Kutei basin.
  4. Initially, the Attaka field consisted of six wellhead platforms producing oil from 52 wells, and the central platforms comprised the Quarter Platform, Processing Platform, and Gas Compression Platform. After 1980, additional platforms and wells were added to maintain production and maximize the hydrocarbon recovery. It eventually had a total of 22 platforms and 109 wells, five of which are subsea wells.
  5. Five subsea wells were completed in 1981-1984 to produce the oil accumulation in areas out of reach of the existing remote platforms. These are the first subsea completions in Indonesia and in Asia.
  6. Initially, its produced associated gas was flared. Finally, the flaring stopped with the completion of the Badak LNG plant in 1977. Unocal, Total Indonesie, and Huffco were the gas suppliers to the Badak LNG plant.
  7. Attaka wells have very high permeability. It is as high as 5 Darcy in some wells.
  8. Attaka field’s daily oil production peaked at 116,950 BOPD in December 1977 and gas production peaked at 174 MMSCFD in October 1980.
  9. A significant milestone was reached when cumulative oil production of 600 million barrels was recorded at 6:42 PM on March 7, 2001. Cumulative gas production in that same year was 1.3 trillion SCF.
  10. Attaka field has more than 50 sands with variable oil reserves at depths between 2800 and 7600 feet. Reservoir sand thickness ranges from 5 to 100 feet. A multiple zone completion method using dual tubing strings and multiple packers was selected to produce them economically. This method allows the engineers the flexibility to select from which of the 2 to 4 perforated zones in each well they would like to produce

Decommissioning of Platform EB

The Attaka field has been producing oil and gas for 50 years and its production has been declining for the past 30 years. The field is currently producing less than 5000 BOPD.

Finally, the Attaka field’s EB Platform was decommissioned in November 2022. It is the first decommissioned offshore oil platform in Indonesia.

Interestingly, the EB Platform was not the oldest platform in the Attaka field. In fact, it was one of the latest platforms built in Attaka. Platform EB was built in 2000 to replace Platform E that was burnt down due to the blowout of Well E-20 in August 1997.

The EB platform was built to accommodate the drilling of seven 7 fully insurance-reimbursable wells to tap reserves estimated at 3.25 million barrels of oil and 18.5 BSCF of gas.

Jamin Djuang – A former Production Supervisor of the Attaka Field in 1980.