Pertamina has completed the construction of the 67 km gas pipeline supplying gas to its Unit II Refinery in Dumai. With the commissioning of the 24-inch pipeline on 14 April 2019, the fuel needed to operate the refinery is now supplied by the gas produced from the nearby gas fields.
The gas comes from the following three blocks:
The prolific Grissik field located in the Corridor Block which is operated by ConocoPhillips. The Grissik field produced more than 900 MMSCF of gas per day in 2018. With an area of 2258 square kilometer, the Corridor Block is one of the largest gas blocks in Indonesia. Other very large gas blocks are the Tangguh and the Mahakam blocks.
The fields located in the Bentu Block which is managed by PT Mega Energi Persada (PT EMP). The Bentu Block is located near the city of Pekanbaru. PT EMP also supplies its gas to Indonesia’s state power company (PLN) and Riau Andalan Pulp and Paper (RAPP).
The oil and gas fields located in the Jambi Merang Block which is now operated by Pertamina Hulu Energi Jambi Merang (PHE Jambi Merang). PHE Jambi Merang acquired the block from the Joint Operating Body Pertamina-Talisman Jambi Merang on 9 February 2019.
In the past, the refinery used the fuel oil, Naptha and fuel gas it produced internally to meet the fuel needs of the refinery.
The project has brought significant economic benefits to both the gas producers and the refinery. In using the gas, the refinery is able to reduce its fuel costs by 40%.
The average crude oil production in Indonesia in 2018 is 803,000 barrels per day according to SKK Migas of Indonesia.
Here are the top ten crude oil producing companies in Indonesia in 2018.
Chevron Pacific Indonesia – 209,000 BOPD
Chevron is the biggest oil producer in Indonesia in 2018 and has been a leading oil producer in Indonesia for more than 90 years. It started operating in Indonesia in 1924 under Standard Oil Company of California.
Chevron operated oilfields in Sumatera and East Kalimantan. It’s East Kalimantan assets came from the acquisition of Unocal in 2005. Chevron handed back all the assets in East Kalimantan to Indonesia government on October 24, 2018, after 50 years of operation under Unocal and Chevron.
Currently, Chevron’s oil production comes mainly from the oil fields located in Riau, Sumatera under the Rokan Production Sharing Contract. The biggest oil field in the Rokan PSC is the Duri field which has been under steam-flood since 1985 and is one of the largest steam flood projects in the world.
ExxonMobil Cepu Ltd – 208,000 BOPD
ExxonMobil Cepu Ltd is the operator of the Cepu block located in Central Java and East Java. The Cepu Cooperation Contract (KKS) was signed on 17 September 2005 and will continue until 2035. ExxonMobil holds a 45% interest in the Cepu block.
ExxonMobil started exploration in 1999, and the oil from the Banyu Urip field started to flow in December 2008.
Pertamina EP – 79,000 BOPD
Pertamina EP operated 21 oil and gas fields located in various parts of Indonesia. These oilfields are managed under five asset groups based on their geographical locations.
Located in North Sumatera and some part of South Sumatera, the Asset One oilfields include Rantau Field, Pangkalan Susu Field, Lirik Field, Jambi Field, dan Ramba Field.
Located in South Sumatera, the Asset Two oilfields include Prabumulih Field, Pendopo Field, Limau Field dan Adera Field.
Located in West Jawa, the oilfields included in Asset Three are Subang Field, Jatibarang Field dan Tambun Field.
Located in Central and East Jawa, the Asset Four oilfields include Cepu Field, Poleng Field dan Matindok Field.
Located in Eastern part of Indonesia, the oilfields in Asset Five are Sangatta Field, Bunyu Field, Tanjung Field, Sangasanga Field, Tarakan Field dan Papua Field.
Pertamina Hulu Mahakam – 42,000 BOPD
Pertamina Hulu Mahakam became the operator of the oil and gas fields located in the Mahakam Block on 1 January 2018. The fields were previously discovered and operated by Total along with Inpex as its partner. They acquired the block in 1966.
Several giant oil and gas fields are located in this block such as the Handil field, the Tunu field, and the Peciko field.
Pertamina Hulu Energi OSES (Offshore South East Sumatera) – 30,000 BOPD
Pertamina Hulu Energi OSES became the operator of the oil fields in Block South East Sumatera on September 6, 2018. The fields were previously operated by CNOOC, China National Offshore Oil Company.
Pertamina Hulu Energi ONWJ – 29,000 BOPD
Pertamina Hulu Energi ONWJ (PHE ONWJ) is currently the operator of the Offshore North West Java (ONWJ) production sharing contract following the change of company ownership from BP to Pertamina in July 2009.
The contract area, located in the Java Sea, covers an area of approximately 8,300 square kilometers – stretching from the North of Cirebon to Kepulauan Seribu.
The giant Ardjuna field is located in this Production Sharing Contract area. It was discovered by ARCO – Atlantic Richfield Company – in 1969 and operated by ARCO until BP – British Petroleum – acquired ARCO in 2000.
The production facilities consist of 670 wells, 170 shallow water platforms, 40 processing and service facilities and some 1,600 kilometers of sub-sea pipeline.
Medco EP Natuna – 16,000 BOPD
Medco EP Natuna, a subsidiary of Medco Energi, is the operator of the South Natuna Sea Block B. The field was initially operated by ConocoPhillips until Medco Energi acquired it in 2016.
Besides producing oil, Medco EP Natuna also supplies gas to Singapore using a 656 KM long 28” subsea pipeline.
Petronas Carigali (Ketapang) – 15,000 BOPD
Petronas Carigali Ketapang operates the Bukit Tua Field located in the Ketapang Block in East Java. Bukit Tua is an oil field but with a significant amount of associated gas. The offshore field is situated at a water depth of about 57 m.
The production facilities consist of wellhead platforms, an FPSO – Floating Production, Storage and Offloading – and onshore receiving facilities (ORF) in Gresik.
PetroChina International Jabung – 14,000 BOPD
PetroChina International Jabung operates the prolific Jabung Block located in Jambi in Central Sumatera.
The company produces crude oil, condensate, LPG and gas. PetroChina supplies gas to Singapore using a 450 KM long subsea pipeline.
An interesting aspect about the block is that PetroChina discovered the fractured basement rock contains a significant quantity of gas can flow at significant rates.
Pertamina Hulu Kalimantan Timur – 13,000 BOPD
Pertamina Hulu Kalimantan Timur operates the East Kalimantan-Attaka Work Area. Chevron was the previous operator of the work area until it handed over the operatorship to Pertamina on October 25, 2018.
Attaka, the famous giant oil field is located in this block. The Attaka field was discovered and operated by Unocal until Chevron acquired it in 2005.
The oil fields in this work area are in the late declining phase. Around one billion barrels of oil and 3 TCF of gas have been produced from this work area.
Here are the key concepts and methodologies which a reservoir engineer should understand to simulate a reservoir effectively, according to Emeritus Professor Val Pinczewski of the University of New South Wales.
The internal structure of reservoir simulators – single, two and three phase reservoir simulators, black oil and modified black oil simulators, compositional simulators.
Limitations of numerical solution methods – truncation errors, numerical dispersion and stability, grid orientation effects.
Rock properties and saturation functions – design of effective SCAL programs and reservoir wettability, two and three-point saturation end-point scaling, rock-typing and hydraulic flow units, Leverett J-Function and Corey based models for relative permeability and capillary pressure, averaging saturation dependent property data, limitation of three-phase relative permeability and capillary pressure models.
Upscaling and relative permeability pseudo-functions – dynamic pseudo-functions, vertical equilibrium, and viscous dominated pseudo-functions.
Grid selection – advantages and disadvantages of structured, unstructured and hybrid gridding systems, corner-point geometry grids, PEBI grids, locally orthogonal grids, vertical heterogeneity and layering, guidelines for grid design.
Model initialization – Capillary-gravity equilibrium, initialization with zero capillary pressure, initialization using an average capillary pressure curve, initialization using the Leverett J-Function and a reference capillary pressure curve, initialization using Eclipse SWATINIT method. Effect of different options for run-time capillary pressure.
Aquifer modeling and history matching – unsteady-state water influx, Hurst and van Everdingen model, Carter-Tracy and Fetkovich models, material balance and aquifer history matching, guides for effective aquifer model history matching.
Well models and gas condensate reservoir modeling – condensate blockage and the two-phase pseudo-pressure method, implementation of the method in commercial reservoir simulators, gas condensate inflow relationships, PVT and fluid flow relationships for gas-oil relative permeability ratios, gas relative permeability ratio as a function of gas-oil relative permeability ratio, high velocity effects, positive and negative coupling, velocity dependent relative permeability and capillary number, guidelines for running gas condensate reservoir simulations using commercial reservoir simulators.
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:
USA – 15.6 Million barrels of oil per day
Saudi Arabia – 12.1 Million BOPD
Russia – 11.2 Million BOPD
Canada – 5.0 Million BOPD
China – 4.8 Million BOPD
Iran – 4.7 Million BOPD
Iraq – 4.5 Million BOPD
UAE – 3.7 Million BOPD
Brazil – 3.4 Million BOPD
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.
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:
Shale oil and shale gas.
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 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.
Open-pit mining method is commonly used to extract the oil from oil sands located near the earth 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
composed of clay that is rich in organic materials. Since tight shale has very low permeability, 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.
Indonesia will build the largest tidal power plant in the world in the straits of Larantuka at the Island of Flores. The power plant is designed to provide electricity to more than 100,000 residents in that area.
This Larantuka power plant project aligns with Indonesia’s commitment to increase the share of renewable energy in the total energy supply to 25% by 2025. It also commits to reduce the emission of CO2 by 300 million tonnes by 2030.
The tapping of ocean energy, consisting of wave and tidal energy to produce clean and cheaper power will grow significantly. According to Market Research Future, the annual growth rate of the global wave and tidal market is expected to be more than 17% till 2023.
Watch this spectacular USGS video showing lava laze formed by the lava of Kilauea volcano flowing into ocean at Kapoho bay on June 4, 2018.
The lava is from Kilauea Volcano’s lower east Rift Zone entering the ocean. The ocean entry is about a half-mile wide. The flow sends a large laze plume into the air along the coast.
What is lava laze?
When the lava flow goes into the ocean water, it boils the water and creates a white acidic plume. That’s laze.
“It’s a complex chemical reaction that occurs between the lava flow and seawater,” said Wendy Stovall, a volcanologist with the U.S. Geological Survey. “It creates a mixture of condensed acidic steam, hydrochloric acid gas and tiny shards of volcanic glass.”
From the air, the plume looks like exhaust from a factory or the white smoke released during a forest fire.
If you’re underneath the plume, a light sprinkle of rain as corrosive as battery acid can fall on you. The acid can burn your skin, irritate your eyes and make it difficult to breathe. In rare cases, the damage can be permanent.
Geothermal plants can be safely situated near a volcano, says Dr. Roland Horne, Thomas Davies Barrow Professor in the School of Earth Sciences and Senior Fellow at the Precourt Institute for Energy at Standord University.
In this article, Dr. Roland Horne discusses geothermal energy in the face of natural hazards and a way to tap the earth’s heat far from volcanoes in the future.
I highly recommend you read the article that I mention above. In this article you can also watch the awesome lava flow from a fissure of Mt. Kilauea on May 19, 2018 and learn about Stanford University’s School of Earth, Energy & Environmental Sciences.
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
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.
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
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.
Course date: November 19-23, 2018