I was honored to be asked to write the following article for the Jakarta Post's special edition that was published for the Indonesian Petroleum Association (IPA) 2017 Conference and Exhibition.
This article covers four main areas for oil and natural gas prospecting in Indonesia as follows: Prospective, quality and depth of geological data, regulations, and incentives, and what needs to be done.
Prospective reserves similar to the Duri and Minas fields which were discovered during the second world war will be difficult to find and may not exist, but who knows for sure?
The oil discovery in Cepu, Central - East Java area was only 600 MMBO. However, if we are looking for oil fields of 20 - 50 or 100 MMBO reserves that are close enough to processing facilities, it is believed that these fields do exist.
The Pre-Tertiary Arafura - West Papua, Banda Arch and Bintuni - Salawati Basins are considered prospective for future exploration targets. The USGS has estimated that the mean total of undiscovered resources for oil, gas and NGL from the three geologic provinces, are 4.566 BBO, 60.836 TCFG and 1.839 BBNGL respectively. In Java, pre-volcanic resources along the island are good future exploration targets. There are many sedimentary basins covered by volcanic rocks from the young quaternary volcanoes, numerous oil and gas seeps that have occurred in the volcanic areas of Java Island, geochemically correlated to the pre-volcanic sources. This indicates the presence of active petroleum systems underneath the volcanic covers. Fractured basement reservoirs are also future exploration opportunities, both in Western and Eastern Indonesia. Lessons learned from global success stories are encouraging and need to be heeded by Indonesian Geoscientists.
Many of the deeper horizons have not been properly imaged; stratigraphic traps have not been fully explored. Basins below the young volcanic's can be explored using Innovative technology; so far Magnetotelluric, Gravity and Magnetics have been used to try to image these formations with limited success.
It was stated recently by a respected Earth Scientist (ex Chevron) “that many of the so-called Mature Fields could be classified as New Fields” if new ideas for exploration are adopted. There is a huge potential to develop these, they can become like new discoveries, just by understanding the structure of the reservoirs in detail, albeit some of the reserves may be small in size from 20 to 100 MMBO, they may not be commercially attractive, but if we look at some fields in the USA that only produce 1 – 2 BPD, small fields can become prospective, using mobile processing plants is one answer. As we like to say, “there is more than one way to skin a cat”.
The quality and depth of data that is being offered to potential investors is generally poor, a lot of the data was gathered during 1960 - 2000, as well as data from the Dutch and Japanese occupation eras. Indonesia has complicated geology, deep-water areas, it covers a large area with difficult terrain, which means it is expensive and time-consuming to explore by traditional methods.
An experienced geologist stated that when they went exploring, “they knew that their chances of success were in the region of twenty percent”, this is far too low, the chances of success has to be increased to sixty or eighty percent.
The reality is, Indonesia’s oil & gas potential is still not well explored, huge potential still awaits discovery. Innovative technology is required which can be integrated with existing data; this then becomes a new cycle of exploration, targeting the deep and smaller structural and stratigraphic traps, as well as the overlooked shallow targets, both onshore and offshore.
In regard to regulations and incentives, for Indonesia to be aware of its resources and reach its full potential, improvements are needed in the legal and regulatory frameworks as well as fiscal incentives to attract investment.
This needs consistency of regulations and not a constant change of ministers, changes of top positions in the state-owned oil company, all of whom have their own ideas, this has resulted in many changes of staff in key positions, which means there has been very little stability in policies. Indonesia has become more protective, giving more responsibility to the state-owned company; it is well known that national companies do not perform as well as private companies that are answerable to their shareholders. Indonesia’s resource industry is not the most attractive for local and international investors.
The government of Indonesia (GOI) has introduced several regulations such as the “Gross Split” scheme, although in my opinion, none of these address’s the real issue, which is simple “reliable resource data is required” the only way to obtain reliable data is to carry out exploration, the GOI is still expecting investors to be interested in tendering for a license, although the terms are not conducive for investors. If local banks and entrepreneurs will not invest in the exploration of their country’s resources as they consider that the risk is too high, how can Indonesia expect international investment? (if they even want it, as Indonesian politics has boosted the appeal of resource nationalism within policymaking circles). They cannot, although the GOI constantly states, we need investment to carry out exploration.
Credit has to be given to the regulators for addressing some of the problems, although one wonders if the bigger picture is being looked at. All anyone seems to talk about is the low price of oil, it is stated that exploration is too expensive and the cost of oil is too low, this is a "Chicken and Egg" situation, be time the price goes up (if ever) we start exploration, then the cost of oil comes down, the next excuse is that the cost of oil is too low to exploit what has been found, this is the scenario if we continue to explore with traditional methods. What happened when the price of oil was high?
It also does not help when amendments to the 2001 oil and gas law are delayed or pending at the “House of Representatives” for the past four years. Although it is understood that the final draft has just been submitted as I am publishing this article, although it is expected the regulations will be some time before it is finalized.
What is the solution? The GOI along with the private sector of Indonesia should bring the banks on board to invest in their own country for a comprehensive knowledge of the country's resources, we all know that to explore the whole of Indonesia is not possible, due to terrain, geology, cost and time, which makes many parts of Indonesia unexplorable, therefore Indonesia will never know what resources it truly has, it will continue to say we are rich in resources without knowing where they are. Indonesia should know what resources it has, Indonesia can not keep saying it is rich in resources without being able to support this statement.
Therefore the GOI needs to be responsible for the exploration of their own country, both onshore and offshore, different methods of exploration that enhances traditional methods has to be used, methods that have been well proven but not believed by many geoscientists in Indonesia because they are not aware of other methods other than traditional methods, minds have to be opened to innovative ideas, not just “Smart Phone Technology”.
By having reliable resource data, it will attract investors, although if Indonesia continues to expect investors to take all of the risks, investment is not going to happen. Recently several blocks have been tendered with very little if any interest, sorry to say, it is not just the oil price that is unattractive, the terms and conditions are also unattractive, is anyone really asking the question, why are investors not interested?
Anyone who tenders for a block needs to be assured that they have a reasonable chance of success, not a 10 - 20% chance of success, but a 60 – 80% chance, this then becomes interesting. The cost to tender can be increased as the data in the data bank means something, then the gross split may work, as the investor knows that they will get a return on their investment.
The technology is available that allows Indonesia to be fully aware of its resource potential, which will allow traditional tools of exploration such as seismic to become a confirmation tool instead of an exploration tool, in areas that seismic is effective, not in volcanic areas.
At the end of the day, if geologists are honest with themselves, they need help, they need data and they need jobs, exploration is not happening as it should for all the reasons that have been stated, the solutions are available.
We should not be drilling unless we know that the risk has been reduced, the cost of innovative exploration is a fraction of drilling a dry hole on land and offshore in deep water, Innovative Exploration Technology needs be used which supports and enhances the knowledge of any given area. The whole of Indonesia then becomes explorable.
Indonesia needs to invest in its self, it needs innovative ideas to achieve its goals.
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Source: U.S. Energy Information Administration, Monthly Refinery Report
The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.
The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.
Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.
Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report
When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.
Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.
By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.
East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.
Headline crude prices for the week beginning 7 October 2019 – Brent: US$58/b; WTI: US$52/b
Headlines of the week
In the October 2019 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts lower crude oil prices in the fourth quarter of 2019 and in 2020 despite tighter global balances. The tighter balances are largely the result of unprecedented short-lived loss of global supply following the September 14 attacks on crude oil production and processing infrastructure in Saudi Arabia. The production declines contribute to overall stock draws in the second half of 2019 with a relatively large stock draw in the third quarter. In the fourth quarter, however, EIA forecasts global supply growth will outpace global demand growth, resulting in an inventory build, offsetting some of the third quarter draws (Figure 1). EIA lowered its crude oil price forecast for the fourth quarter of 2019 by $1 per barrel (b) to $59/b, reflecting current price trends, and lowered its crude oil price forecast for 2020 by $2/b to average $60/b because of expected supply growth.
In the October STEO, EIA forecasts total global petroleum stocks in the second half of 2019 will decrease by an average of 290,000 barrels per day (b/d), compared with the September STEO forecast stock build of 250,000 b/d for the same period. EIA forecasts total world crude oil and other liquids production for the second half of 2019 to average 101.3 million b/d, down by 550,000 b/d from the September STEO. Most of the production decline is the result of lower output from Saudi Arabia, reducing the collective output of the Organization of the Petroleum Exporting Countries (OPEC) to 34.8 million b/d for the second half of 2019.
In the October STEO, EIA assumed the Abqaiq facility and Khurais oil field would produce at their pre-attack levels by the end of October. Compared with the September STEO, EIA revised OPEC spare capacity, most of which is located in Saudi Arabia, lower by an average of 200,000 b/d in the second half of 2019. Saudi Arabia's total capacity (including spare capacity) declined following the Abqaiq attack, and EIA expects Saudi Arabia will use some of its remaining spare capacity to backfill inventories and lost production through the end of 2019. Beginning in January 2020, EIA forecasts that OPEC spare capacity will return above 2.0 million b/d.
Crude oil prices increased sharply following the attacks; Brent front-month futures prices rose by nearly 15% on Monday, September 16, the first day of post-attack trading. This increase was the largest one-day percentage increase on record for Brent front-month futures prices. The increase was larger in the front months of the futures strip than in the later months, indicating the market expected the outage to be relatively short lived, and prices fell quickly after the attack (Figure 2). Saudi Arabia continued to export crude oil by drawing from inventories, increasing production in other fields, and reducing domestic refinery inputs. Abqaiq's relatively quick return to operations likely lessened the extent and duration of the price increases. Brent front-month futures prices fell to lower than pre-attack levels on October 1, settling at $59/b for the December contract and have fallen slightly since then.
The relatively quick return to pre-attack price levels likely reflects demand-side concerns and increased down-side price risk. Despite tighter forecast global petroleum markets in the second half of 2019, EIA expects that the Brent crude oil price will average $60.63/b in the second half of 2019, nearly unchanged from the $60.68/b forecast in the September STEO. EIA forecasts that global petroleum inventories will increase by nearly 550,000 b/d in the first half of 2020, which is expected to put downward pressure on crude oil prices. EIA forecasts the price of Brent crude oil to average $57.34/b during the first half of 2020. However, EIA expects the price of Brent crude oil to increase to $62.48/b in the second half of 2020 as global petroleum stock builds slow and petroleum balances are relatively tighter than during the first half of the year.
The price forecast is highly uncertain and supply or demand factors may emerge that could move prices higher or lower than EIA's current STEO forecast. Driven by revisions to global economic outlook, EIA has revised its 2019 liquid fuels demand growth outlook lower in the STEO for the last nine consecutive months and 2020 consumption has been revised down eight of the last nine months. EIA's price forecast also accounts for a higher level of petroleum supply risk in the aftermath of the attacks in Saudi Arabia.
U.S. average regular gasoline prices increase slightly, diesel prices fall
The U.S. average regular gasoline retail price rose less than 1 cent from the previous week to $2.65 per gallon on October 7, 26 cents lower than the same time last year. The West Coast price rose by nearly 10 cents to $3.64 per gallon, and gasoline prices in California continued to rise, increasing by 14 cents to $4.09 per gallon, 55% higher than the national average and 39 cents higher than the same time last year. The Midwest price increased by more than 1 cent to $2.50 per gallon, and the Rocky Mountain price increased by less than 1 cent, remaining at $2.71 per gallon. The Gulf Coast price fell by more than 4 cents to $2.28 per gallon, and the East Coast price fell by 2 cents to $2.49 per gallon.
The U.S. average diesel fuel price fell nearly 2 cents to $3.05 per gallon on October 7, 34 cents lower than a year ago. The East Coast and Gulf Coast prices each fell by more than 2 cents to $3.04 per gallon and $2.80 per gallon, respectively, the Midwest price fell by 2 cents $2.97 per gallon, the Rocky Mountain price decreased 1 cent to $3.02 per gallon, and the West Coast price decreased by less than 1 cent to $3.64 per gallon.
Propane/propylene inventories increase
U.S. propane/propylene stocks increased by 0.1 million barrels last week to 100.8 million barrels as of October 4, 2019, 11.9 million barrels (13.4%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast inventories increased by 1.0 million barrels, and Midwest inventories rose slightly, remaining virtually unchanged. East Coast inventories decreased by 0.9 million barrels, and Rocky Mountain/West Coast fell slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 4.4% of total propane/propylene inventories.
Residential Heating Fuel Price Survey Begins This Week
Beginning this week and continuing through the end of March 2020, prices for wholesale and residential heating oil and propane will be included in This Week in Petroleum and on EIA's Heating Oil and Propane Update webpage.
As of October 7, 2019, residential heating oil prices averaged nearly $2.95 per gallon, 41 cents per gallon lower than at the same time last year. The average wholesale heating oil price for the start of the 2019–20 heating season is $1.99 per gallon, over 48 cents per gallon below the October 8, 2018, price.
Residential propane prices entered the 2019–20 heating season averaging nearly $1.86 per gallon, 53 cents per gallon less than the October 8, 2018, price. Wholesale propane prices averaged more than $0.58 per gallon, 43 cents per gallon lower than the same time last year.