A quarter million dollars for mud? Mud for a single horizontal well can cost that much and more. As horizontal well laterals keep getting longer, they need that much more mud. So the $10 billion drilling mud fluids business is growing fast. The industry has a unique supply chain, with production, storage and distribution infrastructure that rival other aspects of the oil & gas drilling business. But you don’t hear a lot about mud. It is one of those unsung heroes of the shale revolution, getting little attention in industry press or the investment community. But producers know they can’t do their job without just the right mud formula. Today we begin an in depth look at drilling mud fluid and its importance to shale drillers.
Posts from Callie Mitchell
Big increases in LPG (propane and butane) exports are planned for the west coast. In March (2014) Petrogas purchased the Ferndale, WA terminal from Chevron – the only existing west coast LPG terminal. Then in April, Sage Midstream announced that the company is developing another LPG terminal about 200 miles south at the Port of Longview, WA. Both terminals are primarily targeting propane exports, not the export of butane that has been the mainstay of Ferndale for decades. What is the logic behind these deals? What needs to happen to make them work? Today in this second part of our series on the new west coast LPG game, we take a closer look at these two facilities, including their potential supply and market destinations.
All the export LPGs on the West Coast are in a tank in the middle of Washington State in somebody else’s name. So if you’re dreamin’ about LPG exports, the West Coast is a brand new game. Apologies to Larry Gatlin.
On March 4th, Petrogas announced the purchase of the Ferndale, WA LPG terminal, the only functioning butane and propane export facility on the U.S. west coast. Then last Thursday (April 10th) Sage Midstream announced a project to build another world scale LPG (liquefied petroleum gas) export terminal a couple of hundred miles south at the Port of Longview, WA. These are big developments for the west coast LPG markets. Today we begin a blog series that examines the history of Ferndale, how it has been used in the past, and what these two announcements mean for the future of west coast propane and butane markets.
The recent propane shortage is being called a “crisis” and for good reason. But like so many “crises” there is more to the story than is generally known and in this case it’s worth a careful examination of the events involved. Clearly it was a perfect storm in the balance of supply and demand, resulting in huge price spikes. And the consequences included panic, headline news, government intervention and of course, lots of finger pointing. Today we look at how the market responded and why the propane industry will once again be stronger for it.
NGL volumes continue to climb because of all the surging “wet” shale gas production. These days about 7% of gas plant NGL production is “isobutane”, (also known as IC4, I Grade, methylpropane, R600a, iso and “izo” to our friends in Canada). Over the past two years gas plant production of iso is up about 25%, and that volume is expected to increase another 30% over the next two years. Most isobutane is used by refineries to make high-octane alkylate, but what about the rest? Today we take a closer look at this lesser known natural gas liquid (NGL) and the sometimes exotic uses it is put to.
The northern corn-belt states are winding down from a very wet bumper crop of corn which has required a lot of grain drying, fired by propane. That has translated into a shortage of propane supplies – so much so that seven governors recently issued emergency orders to expedite propane deliveries to their states. Now, with about three weeks left before the official onset of winter (and it feels like winter already), 2013 Midwestern propane problems should be behind us. But what about next year? In 2014, Cochin pipeline – one of the most significant traditional sources of propane for the region goes away. Kinder Morgan (current owner and operator of Cochin) is reversing the system and turning it into a diluent pipeline. Volumes of propane previously delivered by Cochin must come from somewhere else. Today we’ll continue our series looking at upper Midwest propane and how the region is likely to adjust in the post-Cochin market.
Recap from Part 1
In Part 1 of this Farmer Dries Corn and I do Care series we looked at the reasons propane use for corn drying spiked this year, where propane for the Midwestern corn belt usually comes from, what has happened to propane prices lately, and mentioned the fact that Cochin is being reversed. This time we’ll get into the details of what that reversal could mean. Cochin has traditionally been a big player in this market. The 12-inch pipeline runs 1,900 miles between Fort Saskatchewan, Alberta and Windsor, Ontario, cutting through the U.S Midwest on the way. It can be operated as a batched system, but in recent years it has moved mostly propane into Midwestern terminals. Capacity is about 70 Mb/d.
Shrinking Throughput but Big Propane Demand Swings
Figure #1 below provides half of the story of why Kinder Morgan is reversing the system. Canadian volumes being imported on the pipeline have been falling for years. Back in the 2000s, Cochin was moving 40-50 Mb/d, or about 60% of capacity, sometimes spiking up to 60 Mb/d. But that started to fall off in the late 2000s, even though the pipeline would still see some big spikes in utilization during the winter. Meeting demand on those big spikey demand days may be good for the market, but is not so good for your pipeline economics when average utilization of your pipeline is getting down below 35%. Then starting early in this decade, the Midwest started getting more propane from that big source of hydrocarbon production right next door – the Bakken, and pipeline utilization fell to only 22%. It’s hard to make money with a pipeline when capacity utilization is that low, so Kinder Morgan certainly has had the motivation to repurpose this asset. Note though, that the pipeline still has spikes of throughput in the corn drying and winter heating seasons.
Figure 1 (Click to Enlarge)
Growth in Diluent Demand
On the flip side, Canada seems to have an almost insatiable appetite for diluent to blend with Canadian bitumen to make pipeline transportation possible (see Like A Box of Chocolates – The Condensate Dilemma). As we’ve discussed in the RBN blogosphere many times, Canadian heavy crude oil (bitumen) is too viscous to be moved in pipelines without either putting it through an expensive upgrading unit or mixing it with diluent to – in effect – thin it out. About 40% of Canadian crude is blended with diluent (mostly natural gasoline or lease condensate) and that percentage is increasing. That will push Canadian demand for diluent above 600 Mb/d by 2018, with only about 150 Mb/d coming from Canadian sources. The rest will need to be imported from the U.S.
The Enbridge Southern Lights pipeline (see Fifty Shades of Eh) supplies most of that market today. But Cochin is a perfect contender to provide a big piece of the additional capacity required by Canadian bitumen producers. Kinder Morgan is spending about $260MM to reverse the 1,500 miles (and 25 pump stations) of the Cochin line to move diluent into the Alberta market. By July 2014, Cochin will move up to 95,000 bpd of diluent (lease condensates and natural gasoline) via a connection to the Explorer Pipeline in Kankakee County, Illinois to their existing terminal facilities near Fort Saskatchewan, Alberta. Kinder Morgan has already secured 10 year (minimum) commitments for essentially all of their capacity. Of course, this means taking Cochin out of propane service.
It’s a classic example of supply and demand. At the end of the day, product will move to the point where it is most in need. In this case, it’s smart business to fill Cochin 100% with diluent versus a declining volume of propane. It’s something that the Midwest propane markets have been and will continue to adapt to. Midwestern agriculture and heating demand which were original drivers to what was considered the foundation of the most advanced and leading edge pipeline and distribution infrastructure back in their day, including Cochin, is now faced with a new world.
The good news and the most fundamental to this new world is the fact that North America is officially long propane, and that length is coming from a new and once unpredicted source, the shale plays in neighboring North Dakota; and it’s just a tank car or truck delivery away. Canada also has more propane lately, and even though a lot of it previously came down Cochin, it too is (and always has been) just a tank car delivery away.
Corn drying in the Midwest is finally wrapping up, but farmers and grain elevators are still short of propane supplies even after emergency orders were imposed by several Midwestern governors. The shortage has contributed to a spike in propane prices and the Conway, KS market jumped above Mont Belvieu last week for the first time since February 2011. But, there is more to the story. The upper Midwest is enjoying the largest bumper crop of corn in the record books, and due to recent weather it is “wet” corn needing more drying, thus more propane. With the U.S. “bumper crop” of propane from processing shale gas flooding the market, you might wonder why there is a problem. Clearly the answer is logistics – having the barrels at the right place at the right time. And that’s the reason for more concern when we get to next year. Because one of the primary propane supply conduits to the Midwest – Cochin pipeline - goes away in early 2014. Today we start a series to look at what’s going on with Midwest propane and how that market is likely to change when Cochin is reversed and turned into a diluent pipeline.
The oil and gas pipeline industry depends on “Pigs” (pipeline integrity gauges) to verify pipelines. They help avoid leaks, fractures and costly unscheduled service interruptions. As massive new oil and gas pipeline construction continues in the US and as existing pipelines get older the pig business is becoming more valuable. But like anything else, they aren’t perfect; and pigging experts and pipeline operators are motivated to make them better. Today we continue our analysis of the pig business with a look at what some of the movers and shakers are doing to support new demands and challenges in this booming industry.
The pig, or “Pipeline Integrity Gauge,” is a sophisticated device that is critical to the safety and integrity of pipelines. The oil and gas pipeline transportation industry can’t live without them. They help ensure the safe and efficient passage of crude oil, NGLs, petroleum products and natural gas through more than 2.3 million miles of pipeline in the U.S, according to PHMSA (Pipeline and Hazardous Materials Safety Administration). Over 3,000 pipeline operators in the U.S. manage this transport system. Their success is due in large part to pigs. Today we investigate the role of pigs in oil and gas pipeline transportation infrastructure.
College football season has started once again, but we want to be clear that today’s blog is not about the Arkansas Razorbacks or the “pig” they throw around. It’s about another kind of “pig,” one that is critically important to the oil and gas pipeline industry. This kind of Pig can cost over $500,000 and it does its work inside pipelines.
Pigs help keep pipelines round, clean and blemish free
There are lots of stories out there about why these contraptions are called “pigs”. One, that seems logical, is the fact that “pig” is an acronym for “Pipeline Inspection Gauge”, or “Pipeline Integrity Gauge.” But maybe they got their name from the squealing sound they make when traveling through a pipeline or the fact that after traveling through a pipe they look like a pig, covered in muck? Another story is how in the late 1800’s balls of pig leather (and other things) were used to clean pipes (which were then made from wood). No one really knows for sure.
What we do know is that pigs performed over 50,000 pipeline inspections in 2012 alone - along nearly 90,000 miles of pipe, according to PHMSA. There are many different kinds of pigs but they are used in pipelines for three main reasons:
1. Cleaning —better flow, more throughput, efficiency, corrosion control
2. Batching and Separation —separating product batches such as diesel and gasoline to keep them from mixing
3. Inspection —safe product flow and mapping
Pigs come in all shapes and sizes (Figure 1). There are simple pigs (sometimes called “dumb” pigs), and there are complex high tech pigs (a.k.a “smart” pigs). The more sophisticated smart pigs are used as in-line inspection tools. Smart pigs are typically owned and operated by specialty services companies. Dumb pigs are typically used by pipeline operators for cleaning and batching.
Figure 1: TD Williamson Pigs (Click to Enlarge)
Pigs can be metal, foam, plastic or gel and can have special add-ons like “scrubbers.” Their length can range from a few inches to over seven feet long, and whatever width it takes to fit (generally “snugly”) inside a pipe. Sometimes they look like dumbbells and sometimes porcupines. They move through pipelines propelled by added pressure from pipeline compressors or pushed by whatever product is in the pipeline. Pigs are launched into the pipeline at an injection location, such as a valve or pump station (from as you may have guessed, a “pig launcher”) and directed by the flow of the product in the pipeline until they reach the end of the testing or cleaning area. At the end of the line, pigs are removed into a receiver (or “pig trap”). If the pig is smart, the tool is removed, and the recorded data is collected and analyzed.
Smart pigs were developed in the 1960’s and provide “intelligence” by recording data inside the pipeline (Figure 2). The data collected might include measuring the level of damage and/or corrosion, or mapping an entire pipeline system for asset management purposes. New technology makes them even “smarter”. Pigs can now employ a variety of technologies like Magnetic Flux Leakage (MFL) and Global Positioning Systems (GPS) to record data about the condition of the pipeline. For example, if there’s a dent in the pipe wall, its exact quadrant and coordinate can be pin pointed. But the value of that data still has to be extracted by analysis. And smart pigs generate myriads of data – that is only useful if it is properly interpreted.
Just like every other kind of mechanical equipment, rail tank cars require maintenance every once in a while. Valves can leak. Linings wear down. Railings, platforms, and brake equipment need periodic repairs. And not surprisingly, the more miles you put on a tank car, the more maintenance it is going to need. As the crude-by-rail phenomenon has grown, so has the rate of ‘bad orders’ – rail cars that must be taken out of service for maintenance. Handling bad orders is a new issue for many producers and refiners just now getting their feet wet in the business. Everyone agrees that this is a very important issue, and the rail industry is not taking it lightly. Today we explore the implications of bad orders in the crude-by-rail market and how progressive solutions are on their way.
Crude-by-rail has had a huge impact on the market for tank cars. Currently there are 53,000 tank cars on back order and more orders are coming in. That’s up from a backlog of 48,000 just a couple of months ago. The tank car manufactures are enjoying every bit of it but for the first time since the ethanol boom, they can’t keep up. In the old days it took 9 months to deliver a new car. Now, there is such a backlog that manufacturers can’t deliver a new car for 24 - 30 months. Today we will review the rapidly evolving tank car situation based on a recent presentation made by Travis Brock from Strobel Starostka, a construction and rail services firm deeply involved in in the crude-by-rail markets.
These days natural gas can be traded in spot, term, or financial at over 120 locations across the US. Deals can be executed by Apps, by instant messages and by high-speed algorithm. And it is reported that a few human beings actually still trade gas bilaterally over the telephone as was done in the time of the Cro-Magnons. None of that would be happening without the big bang. Today we recall how the dust settled after the big bang in natural gas markets.
Storage, the great balancing mechanism of the natural gas market in North America is heading toward another evolution in its usage, flow patterns and economics. Not too many years ago, natural gas storage was the hottest midstream investment opportunity going, expected to synchronize inbound flotillas of LNG imports with seasonal domestic demand. Winter vs. summer price differentials were wide, prices were volatile and storage economics looked great. When shale gas happened, those differentials evaporated along with storage economics. Today another phase looms for natural gas storage as Marcellus and now Utica production ramp up on top of (or more accurately, underneath) the largest storage region in the world – the Northeast U.S. This is a big topic with big implications. So rather than jumping into the middle of the upcoming gas storage transformation, we will walk through a multi-part North America natural gas storage blog series - its history and status, its challenges, who’s involved, and finally what could be in store going forward. Today we’ll start with some natural gas storage basics.
Today’s blog is something different. It is a special feature covering a unique aspect of the NGL/LPG industry, known as the LPG Charity Fund. The organization is an integral part of this community, due both to its good works and its widely attended extracurricular events. In posting this blog we are not asking for contributions, volunteers or anything else. Instead, we just think it is important – when you are trying to understand an industry – that you know something about the people involved and how the market really connects. Today we talk about this important dimension of the NGL/LPG community.
The isobutane market has a traditional self-correcting mechanism whenever the market gets oversupplied - the iso vs. normal spread declines, the merchant isomerization units shut down, and the market moves back into balance. But there is a potential problem ahead for this orderly, self-correcting marketplace – shale. As high-BTU, “wet” shale gas production continues to push NGL volumes from gas plants ever higher, the supply of isobutane will be increasing proportionally. The math is simple. The more gas plant production of isobutane, the less merchant isomerization will be needed. Or is that really true? Could increasing demand for alkylate combined with increasing availability of propylene from dehydrogenation absorb enough isobutane to keep the merchant isomerization units running at high utilization rates? Today in our series on isobutane and isomerization we’ll look at the major isomerization centers, the major players, increasing export patterns and likely scenarios for the disposition of surplus isobutane supplies.