The global oilfield scale inhibitor market was valued at USD 509.4 Million in 2014 and is expected to witness a CAGR of 5.40% between 2015 and 2020. Factors driving the market of oilfield scale inhibitor include increasing demand from the oil and gas industry, wide availability of scale inhibitors, rising demand for biodegradable and environment-compatible scale inhibitors, and so on.
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The oilfield scale inhibitor market is experiencing strong growth and is mainly driven by regions, such as RoW, North America, Asia-Pacific, and Europe. Considerable amount of investments are made by different market players to serve the end-user applications of scale inhibitors. The global market is segmented into major geographic regions, such as North America, Europe, Asia-Pacific, and Rest of the World (RoW). The market has also been segmented on the basis of type. On the basis of type of scale inhibitors, the market is sub-divided into phosphonates, carboxylate/acrylate, sulfonates, and others.
Carboxylate/acrylic are the most common type of oilfield scale inhibitor
Among the various types of scale inhibitors, the carboxylate/acrylate type holds the largest share in the oilfield scale inhibitor market. This large share is attributed to the increasing usage of this type of scale inhibitors compared to the other types. Carboxylate/acrylate meets the legislation requirement, abiding environmental norms due to the absence of phosphorus. Carboxylate/acrylate scale inhibitors are used in artificial cooling water systems, heat exchangers, and boilers.
RoW, which includes the Middle-East, Africa, and South America, is the most dominant region in the global oilfield scale inhibitor market
The RoW oilfield scale inhibitor market accounted for the largest share of the global oilfield scale inhibitor market, in terms of value, in 2014. This dominance is expected to continue till 2020 due to increased oil and gas activities in this region. The Middle-East, Africa, and South America have abundant proven oil and gas reserves, which will enable the rapid growth of the oilfield scale inhibitor market in these regions. Among the regions in RoW, Africa’s oilfield scale inhibitor market has the highest prospect for growth. Africa has a huge amount of proven oil reserves and is one of the leading oil producing region in the World. But political unrest coupled with lack of proper infrastructures may negatively affect oil and gas activities in this region.
Major players in this market are The Dow Chemical Company (U.S.), BASF SE (Germany), AkzoNobel Oilfield (The Netherlands), Kemira OYJ (Finland), Solvay S.A. (Belgium), Halliburton Company (U.S.), Schlumberger Limited (U.S.), Baker Hughes Incorporated (U.S.), Clariant AG (Switzerland), E. I. du Pont de Nemours and Company (U.S.), Evonik Industries AG (Germany), GE Power & Water Process Technologies (U.S.), Ashland Inc. (U.S.), and Innospec Inc. (U.S.).
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Headline crude prices for the week beginning 9 December 2019 – Brent: US$64/b; WTI: US$59/b
Headlines of the week
In the U.S. Energy Information Administration’s (EIA) International Energy Outlook 2019 (IEO2019), India has the fastest-growing rate of energy consumption globally through 2050. By 2050, EIA projects in the IEO2019 Reference case that India will consume more energy than the United States by the mid-2040s, and its consumption will remain second only to China through 2050. EIA explored three alternative outcomes for India’s energy consumption in an Issue in Focus article released today and a corresponding webinar held at 9:00 a.m. Eastern Standard Time.
Long-term energy consumption projections in India are uncertain because of its rapid rate of change magnified by the size of its economy. The Issue in Focus article explores two aspects of uncertainty regarding India’s future energy consumption: economic composition by sector and industrial sector energy intensity. When these assumptions vary, it significantly increases estimates of future energy consumption.
In the IEO2019 Reference case, EIA projects the economy of India to surpass the economies of the European countries that are part of the Organization for Economic Cooperation and Development (OECD) and the United States by the late 2030s to become the second-largest economy in the world, behind only China. In EIA’s analysis, gross domestic product values for countries and regions are expressed in purchasing power parity terms.
The IEO2019 Reference case shows India’s gross domestic product (GDP) growing from $9 trillion in 2018 to $49 trillion in 2050, an average growth rate of more than 5% per year, which is higher than the global average annual growth rate of 3% in the IEO2019 Reference case.
Source: U.S. Energy Information Administration, International Energy Outlook 2019
India’s economic growth will continue to drive India’s growing energy consumption. In the IEO2019 Reference case, India’s total energy consumption increases from 35 quadrillion British thermal units (Btu) in 2018 to 120 quadrillion Btu in 2050, growing from a 6% share of the world total to 13%. However, annually, the level of GDP in India has a lower energy consumption than some other countries and regions.
Source: U.S. Energy Information Administration, International Energy Outlook 2019
In the Issue in Focus, three alternative cases explore different assumptions that affect India’s projected energy consumption:
EIA’s analysis shows that the country's industrial activity has a greater effect on India’s energy consumption than technological improvements. In the IEO2019 Composition and Combination cases, where the assumption is that economic growth is more concentrated in manufacturing, energy use in India grows at a greater rate because those industries have higher energy intensities.
In the IEO2019 Combination case, India’s industrial energy consumption grows to 38 quadrillion Btu more in 2050 than in the Reference case. This difference is equal to a more than 4% increase in 2050 global energy use.
Cumulative U.S. installed onshore wind capacity exceeded 100 gigawatts (GW) on a nameplate capacity basis as of the end of September 2019, according to the U.S. Energy Information Administration’s (EIA) Preliminary Monthly Electric Generator Inventory. More than half of that amount has been installed since the beginning of 2012. The oldest wind turbines still operating in the United States came online as early as 1975.
Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory
As of the third quarter of 2019, 41 states had at least one installed wind turbine. Texas had the most capacity installed, at 26.9 GW, followed by Iowa, Oklahoma, and Kansas. These four states accounted for half of the total U.S. installed wind capacity.
In the United States, wind turbines tend to come online late in the year. Based on information reported in the Preliminary Monthly Electric Generator Inventory, EIA expects that an additional 7.2 GW of capacity will come online in December 2019. EIA also expects that another 14.3 GW of wind capacity will come online in 2020. If realized, the United States would have about 122 GW of wind capacity by the end of next year.
The U.S. Energy Information Administration’s (EIA) Annual Coal Report shows that coal mining employment has declined in the past decade as coal demand has decreased. Most U.S. coal is consumed in the electric power sector and has faced increased competition from electricity generation from natural gas and renewable technologies. U.S. coal mining employment fell from a high of 92,000 employees in 2011 to 54,000 employees in 2018, with the most dramatic decrease in the Appalachian region.
Annual U.S. coal production peaked in 2008, three years before coal mining employment reached its record high. In 2008, the United States produced 1.2 billion tons of coal from 1,458 mines. Since then, coal production has fallen and many mines have closed: in 2018, U.S. coal production was 756 million tons from 679 mines. As was the case with employment, much of coal’s production decline was concentrated in the Appalachian region. More than half of the region’s mines have closed since 2008, and production has fallen from 390 million tons in 2008 to 200 million tons in 2018.
Source: U.S. Energy Information Administration, Annual Coal Report
Appalachian mines tend to be smaller than mines in the Interior and Western regions and to use labor-intensive underground mining techniques, as opposed to machinery-intensive longwall mining and surface mining operations. A slight increase in coal mining employment in the Appalachia region from 2016 to 2018 corresponded to an increase in coal exports because this region is the dominant source of coal shipped overseas.
The decline in operating mines has been steeper than the changes in employment and production. EIA’s review of operating mines showed that smaller mines have had greater difficulty competing in the current market and have been the first to close.
Source: U.S. Energy Information Administration, Annual Coal Report
As smaller, less productive mines were idled or closed, overall coal labor productivity, measured in tons per labor hour, gradually increased from 5.2 tons per labor hour in 2011 to 6.2 tons per labor hour in 2018. The large surface mines in the Powder River Basin (PRB) in Wyoming and Montana have much higher productivity, but even PRB productivity has declined as the region’s producing coal seams become deeper and the amount of overburden, or top soil and rock above the coal seam, increases.
In contrast, the Appalachia and Interior regions both have shown improvements in labor productivity between 2011 and 2018, largely because they are increasingly relying on less labor-intensive longwall and highwall mining systems and closing or idling the least productive mines.
Data from EIA’s Annual Coal Report are available in EIA’s Coal Data Browser. In addition to data from the U.S. Mine Safety and Health Administration, EIA’s Annual Coal Report also includes mine-level data from EIA’s Survey of Coal Production and Preparation and coal exports data from the U.S. Department of Commerce.
Pipelines are the primary method of transporting crude oil in the United States. The increase in U.S. crude oil production in recent years has required the construction of new pipelines and reconfiguration of existing pipelines, including the conversion of natural gas pipelines to crude oil pipelines. The Gulf Coast region, which was responsible for 70% of the growth in U.S. crude oil production between 2010 and 2018, has experienced the largest pipeline buildout during that time period. The Permian Basin, covering West Texas and southeastern New Mexico, contributed the most to crude oil production growth and supported higher crude oil inventories in the region, including increased pipeline fill.
According to EIA’s Liquid Pipeline Projects Database, more than 100 crude oil pipeline projects were completed between March 2011 and September 2019. During this time, about 90% of projects were located in either the Gulf Coast or Midwest regions (Figure 2). The most prevalent project types were pipeline expansions and new pipeline builds. The vast majority of the projects were for transporting crude oil within their respective regions.
Many pipeline expansions increased crude oil takeaway capacity from producing regions. For example, in 2018, Enterprise Products Partners L.P.’s 418-mile Midland-to-Echo 1 Pipeline System was placed into service to transport crude oil from the Permian Basin to locations near Houston, Texas. Other Permian Basin projects completed in 2018 included Plains All American’s Sunrise Pipeline Expansion and Enterprise Products Partners L.P.’s new Loving County Pipeline. The Sunrise Pipeline Expansion transports crude oil from the Permian region to Cushing, Oklahoma, and destinations in the Gulf Coast and the Loving County Pipeline transports crude oil from Permian Basin fields in New Mexico to Midland, Texas, a crude oil supply hub.
About 64% of crude oil production, 52% of U.S. petroleum refining capacity (measured by operable distillation capacity), and 52% of crude oil storage is located in the Gulf Coast (Figure 3). Rising Permian crude oil production decreased crude oil imports, and increased demand for crude oil at petroleum refineries have coincided with several projects aimed at increasing crude oil pipeline deliveries to Gulf Coast refineries. For example, the 264-mile Kinder Morgan Crude & Condensate Pipeline (KMCC), which includes a converted 109-mile natural gas pipeline, initiated deliveries of crude oil and condensate from the Eagle Ford region to Houston in 2012. Kinder Morgan later included a 27-mile lateral to Phillips 66’s refinery in Old Ocean, Texas. In 2014, TC Energy’s Keystone Gulf Coast Expansion was placed into service to supply refineries in Port Arthur, Texas.
In the Midwest, Cushing, Oklahoma—a key crude oil storage hub—has experienced significant increases in crude oil pipeline capacity as new crude oil tank farms were built to handle rising supplies. Crude oil working storage capacity in Cushing rose 59% between March 2011 and September 2019 to reach 76 million barrels. Cushing receives large volumes of crude oil by pipeline and rail from various areas such as Canada and the Rocky Mountains (PADD 4). For example, TC Energy’s 2014 expansion of the Keystone Pipeline transports crude oil that originated in Alberta, Canada, to Gulf Coast refineries via Cushing. Several additional pipeline projects that entered service between 2014 and 2018 were designed to move crude oil from the Rocky Mountains, which includes the Bakken formation, to Cushing.
Growing crude oil exports have also supported increases in crude oil pipeline capacity. The removal of restrictions on U.S. crude oil exports at the end of 2015, combined with higher crude oil production, allowed an increase in crude oil exports in the Gulf region, which grew from 3,000 barrels per day (b/d) in 2010 to 1.8 million b/d in 2018. Petroleum terminals in the Gulf Coast that once imported large volumes of crude oil now load crude oil tankers for export to international destinations. Enterprise Products Partners L.P. recently completed an expansion to its Midland-to-Sealy Pipeline and conversion of its Seminole Red Pipeline to service the Enterprise Crude Houston (ECHO) terminal, a facility where shippers can load U.S. crude oil for export.
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell more than 1 cent from the previous week to $2.56 per gallon on December 9, 14 cents higher than the same time last year. The West Coast price fell 7 cents to $3.34 per gallon, the Rocky Mountain price fell nearly 3 cents to $2.79 per gallon, and the Gulf Coast price fell more than 2 cents to $2.20 per gallon. The East Coast and Midwest prices remained unchanged at $2.48 per gallon and $2.42 per gallon, respectively.
The U.S. average diesel fuel price fell more than 2 cents from the previous week to $3.05 per gallon on December 9, 11 cents lower than a year ago. The West Coast price fell by nearly 6 cents to $3.65 per gallon, the Rocky Mountain price fell by more than 3 cents to $3.21 gallon, the Gulf Coast price fell by 2 cents to $2.76 per gallon, the Midwest price fell by nearly 2 cents to $2.97 per gallon, and the East Coast price fell by nearly 1 cent to $3.05 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.7 million barrels last week to 93.5 million barrels as of December 6, 2019, 7.4 million barrels (8.6%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast and Rocky Mountain inventories increased by 3.3 million barrels and 0.1 million barrels, respectively. Midwest and East Coast inventories decreased by 1.1 million barrels and 0.6 million barrels, respectively. Propylene non-fuel-use inventories represented 5.8% of total propane/propylene inventories.
Residential heating oil prices increase, propane prices decrease
As of December 9, 2019, residential heating oil prices averaged almost $3.02 per gallon, more than 1 cent per gallon above last week’s price but more than 18 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged nearly $2.07 per gallon, more than 2 cents per gallon higher than last week’s price and more than 7 cents per gallon higher than a year ago.
Residential propane prices averaged more than $2.02 per gallon, almost 1 cent per gallon lower than last week’s price and nearly 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.83 per gallon, more than 7 cents per gallon lower than last week’s price and nearly 8 cents per gallon below last year’s price.