The Permian Basin Petroleum Association is a non-profit organization for the promotion of business efficiency and the betterment of Permian Basin oil business through cooperative efforts and the exchange of ideas.
Recollections of the old “Fort Worth Spudder” and other early-day portable drilling machines.
This photo shows what appears to be a stripped-down framework of an old Fort Worth Spudder. See other photos for comparison.
by Bobby Weaver
Probably the most recognizable imagery related to the oil field is a towering derrick. That was especially true in the early days of the industry, when it was not uncommon to see a veritable forest of those derricks clustered in a confined area, creating a sight that all-but-screamed “Oil field!” Such imagery evokes a common assumption dating from those times—the notion that oil wells were drilled only by what came to be called “standard” drilling rigs, having derricks whose tall superstructures were of a semi-permanent nature, which many times stayed in place after a well was completed. What is often overlooked is that a significant number of those early wells were drilled by portable drilling machines, units using either single- or double-pole masts that were folded down when they were moved. Their collapsible nature never lent them the dramatic visual impact of standard drilling rig derricks. Those machines were relatively efficient for drilling as long as well depth remained in the 1,500 to 2,000 foot range and most were suitable for use as workovers in wells up to 6,000 feet in depth.
From the very beginning of the oil and gas industry those portable cable tool drilling units played a significant role. Although developed in the 1870s and 1880s and used primarily for water well drilling, they experienced considerable modification and change over the years, an evolution that witnessed an increase in their drilling capabilities and overall efficiency. By the beginning of the 20th century they were being used throughout the oilfields in the United States.
Cable tool drilling machines are commonly called spudders, although that term is somewhat misleading unless you have some understanding of the machine’s early use. That name developed in the early days when, in order to start a well, a guide pipe was set in the ground to keep the drill bit vertically oriented at the beginning of the drilling process. In the very earliest times putting that pipe in place was accomplished by digging a cellar and setting the guide pipe in by hand. Later that labor-intensive process was abandoned in favor of using the drilling machine itself to actually pound the guide pipe into the ground. The bit used to drive that guide pipe was a blunt-ended drilling device called a spud bit. Because of that process, those drilling machines came to be called “spudders” and from it developed the term “spudding,” or “spudding in,” to identify the beginning process of drilling an oil well. Today, well over 100 years later, the term “spudding in” like so many other oil field terms, has transcended its lowly beginnings and is still used in the oil patch to signify the beginning of the drilling process on a well.
All manufacturers of those machines produced several models, ranging from lightweight machines capable of drilling only a few hundred feet and used to drill water wells to larger models, some of which were rated for as much as 4,000 feet, although the larger ones were rarely used because of weight considerations. In those areas where oil wells stayed in the 2,000-foot range or less, drilling machines were extremely popular both for drilling and running casing. Using them negated the need to employ expensive rig building crews and all the transport problems associated with moving men and construction materials to drill sites. Some were self propelled, but most were towed to the well site by teams of horses or in later times by track-type tractors. In the early days spudders were all steam powered, but by the 1920s just as was the case with the standard drilling rigs, a significant number became powered by internal combustion engines.
There were a number of manufacturers of those drilling machines, but only a few models became widely used. The first practical machine was invented by R.M. Downie in 1879 as a water well drilling device and was manufactured in Pittsburgh under the name Keystone. After a few years Downie moved the operation to Beaver Falls, Pa., where he established the Keystone Driller Company, which over the next decade or so instituted a number of innovations that made their machine suitable for oilfield use—including the step of introducing hard rubber wheels. After internal combustion engines were available in the early 1920s, they introduced some units with crawler-track tractor wheels. Keystone remained among the leaders in portable drilling machines until the 1940s, when the company was dissolved.
By the 1890s the National Supply Company had introduced a skid-mounted drilling machine, though with later models they changed to a wheel-mounted design. The National was advertised as, “The rig that displaced the old standard derrick.” The National played an important role in oil well drilling at least through the 1930s. Along with Keystone, these two makers were part of a large field of nationally known drilling machine companies. In the early days their brands included well known names such as Parkersburg, Columbia, Wolfe, Leidecker, and Buycrus-Erie. There were a host of lesser-known drilling machines whose markets were restricted to the immediate areas where they were built. Meanwhile, yet other, lesser-known lines—makers of machines that were, for all practical purposes, homemade devices—have left little record of their existence beyond a bare mention in local histories.
Beginning in the 1890s and continuing until after WWII, perhaps the most widely used drilling machines in the oil patch were manufactured by the Star Drilling Machine Company of Akron, Ohio. That company boasted that their Akron facility was, “The largest factory in the world manufacturing only portable drilling machines.” They even claimed that, “Ninety-five percent of all oil wells in the world drilled by portable machines were drilled by Star Drilling Machines.” That advertising hyperbole aside, the Star does appear to have been universally popular throughout the oil patch and probably dominated the market.
The machine best remembered in West Texas, particularly in the 1930s through the 1950s, was the Fort Worth Spudder, manufactured by the Fort Worth Machinery and Supply Company of Texas. By 1935 they offered eight sizes of machines capable of drilling from 200 to several thousand feet. Five of those models were heavy duty portable units specifically designed for oilfield use. Their Jumbo J model machine was even advertised as being capable of drilling to a depth of 6,000 feet.
The first documented use of a portable drilling machine in the Permian Basin occurred on January 8, 1921, in association with the Santa Rita #1, whose completion set off the activity that ultimately produced the Permian Basin oil field. Frank Pickrell, who was trying to keep possession of his lease on the Santa Rita property, was running out of time to show good faith on beginning work on the well. Not even having rig builders on the site and with only a couple of days left to begin drilling, he had a portable rig brought in, began drilling a water well to supply the proposed drilling site, and found two passing cowboys to sign an affidavit that drilling was taking place. The ploy worked and more than two years later, using a standard drilling rig, the well was completed at a depth of 3,050 feet and the boom was on. So it could be argued that the Permian Basin discovery well would not have happened without the help of one of those portable drilling machines.
The beginning of Permian Basin activity coincided almost exactly with the changeover to gasoline-powered drilling machines. Because water was critical to the operation of the steam powered machines and the Permian Basin was an arid to a semi-arid region where water was at a premium, equipment that didn’t need excessive amounts of water had an decided advantage. The problem was that almost all the wells were in excess of 3,000 feet, which was at the limit for most of those portable units. Nevertheless, hundreds of those drilling machines were used mostly to drill water wells and to a lesser extent to drill producing wells in areas where the depths ranged in the 2,000 foot category.
There was one major exception to that rule. The Yates field in an isolated region in southeastern Pecos County was discovered in late 1926 and reached flush production in 1929 to became one of the most prolific oilfields of that era, with more than 500 producing wells. One of its wells came in at more than 8,000 barrels and many flowed in the 3,000-barrel range. Most of the early wells in the Yates were drilled at a cost of less than $15,000 each. The low drilling costs can be attributed to a combination of factors: the well depths were in the relatively shallow 1,200- to 1,500-foot range and practically all of them were drilled with portable drilling machines, whose cost of operation was very low.
During the 1930s well depth in the Permian Basin gradually became much greater, which caused cable tool drilling to give way to rotary rigs. During that same time period the portable cable tool machines became more and more obsolete, although they continued to do some in-fill drilling in the older fields and many were converted to well servicing type activities. By the post-WWII era they were mostly an out-of-date curiosity of the past. Today the best and most complete representation of those mostly forgotten pieces of oilfield technology can be found in the outdoor exhibits at the Permian Basin Petroleum Museum at Midland, Texas, where curators have done a remarkable job of preserving those important elements of oilfield history.
Bobby Weaver writes regular for Permian Basin Oil and Gas Magazine. His humor column, Oil Patch Tales (see page tktktktk), appears in every issue.
So many issues. So little time. Playing defense here. Coordinating offense there. Monitoring, testifying, convincing. When it comes to the New Mexico and Texas legislative sessions, the game plan is complex partly because the issues are layered, much like the stacked multi-pay zones that permeate the Permian.
Wheels in Motion
The New Mexico Legislature began its 60-day session on Jan. 15 and will adjourn on March 16. The governor of New Mexico may call the legislature into special sessions; the legislature, itself, can call for an extraordinary session. The New Mexico Constitution does not limit the duration of each special session, and lawmakers may consider only those issues designated by the governor in his or her special session call. The Texas Legislature convened on Jan. 8 for its 140-day regular session, which will end May 27. The governor of Texas is authorized to call additional special sessions as necessary, which cannot exceed 30 days. The governors of both states can add issues to the special sessions they have called.
State Leadership Sets the Tone
Before either gavel fell, the powers that be in the Land of Enchantment and the Lone Star State prioritized their issues. Texas Gov. Greg Abbott, Lt. Gov. Dan Patrick, and new Speaker of the House Dennis Bonnen announced in the early going their intention to focus on property taxes and school finance reform this session. On a similar note, New Mexico Gov. Michelle Lujan Grisham said she will push for additional funding for early childhood education and teacher salaries.
Unpacking the Legislative Layers
No. 1: The Budget
Both states are looking to pump billions into the school system, which will have an impact on the overall budget. When it comes to the budget, two obvious and understandable industry concerns come to mind: tax laws and agency funding.
Oil and gas companies are major taxpayers. In fact, Texas Comptroller Glenn Hegar recently estimated that oil production and natural gas tax collections will generate $10.7 billion for the 2020-2021 budget cycle, which is up some 10 percent from 2018-2019.
As far as budget appropriations, the funding of the industry’s regulatory agency, the Railroad Commission of Texas (RRC or Commission) is THE concern.
“One of the highest priorities for the Permian Basin Petroleum Association [PBPA] and its members in Texas is the funding of the RRC,” said Ben Shepperd, president of the PBPA. “We believe a properly funded Commission is important and critical to ensure the public that we have a strong, effective regulator overseeing the oil and gas industry.”
The RRC has made a baseline budget request of $252.75 million, which is close to its 2018-2019 biennium budget. This amount includes money for an additional 22 full-time pipeline inspectors and $10 million to modernize its IT systems. The agency is not asking for an increase in fees.
As of press time, the Texas Senate and House had just released their preliminary budgets; industry supporters will be maintaining a watchful eye as the budget process continues to play out.
No. 2: Infrastructure
“Whether you’re talking about roads, electrical transmission and distribution systems, or pipelines, infrastructure is a high priority in both Texas and New Mexico,” Stephen M. Robertson, executive vice president of the PBPA, emphasized. “We’re working to ensure that elected officials understand that the economic growth the Permian Basin has provided for both states is only possible if infrastructure growth is supported as well.”
Statutes that could impact infrastructure include changes to eminent domain laws and road funding.
No. 3: Workforce Livelihood
People are a vital component of infrastructure, particularly those doing the work to help make sure everyone else arrives home safely at the end of the day, Robertson noted.
“That’s where the support for cost-of-living increases for the Texas Department of Transportation, Department of Public Safety, and even RRC employees in the Permian Basin comes into play,” he continued. “People are the most valuable asset the Permian Basin has, and we need to support those people.”
To further assist in this area, the PBPA is supporting state-funded programs that repay student loans for doctors, and residency programs that pay doctors who agree to work in Permian Basin communities for four years.
No. 4: Relationships and Understanding
In New Mexico, the PBPA is heavily focused on strengthening relationships.
“There are significant headwinds in New Mexico for the Permian Basin,” observed Mike Miller, government affairs spokesman for PBPA in New Mexico. “The midterm elections brought a sea change from the last administration.”
As new lawmakers learn the landscape, the PBPA is hopeful that they will realize that industry revenue plays a vital role the state’s financial picture, and that working together to address industry concerns is in everyone’s overall best interest. However, early indications have not been encouraging.
“Many of those newly elected officials call themselves progressive and are hostile to oil and gas,” Miller said. “In the first full week of the session, we already began hearing about anti-oil and gas legislation. However, we’re cautiously optimistic we will forge a balance between those who feel we need to have tighter environmental regulations, and those who feel they shouldn’t be so tight that they run everyone out of the state.
“I’m hopeful there will be a nice balance reached,” Miller concluded. “But it will be a continuous, non-stop debate for the entire 60 days.”
When it comes to Texas, the PBPA finds itself on different footing. Few legislators negate the powerful impact the oil and gas industry has in Texas, whether it be pumping up state coffers, boosting employment, or contributions to counties and communities. However, not all legislators understand that in order to continue playing such a prominent role, the Permian Basin requires special attention.
“Our main objectives in Texas all center on the need to convince those elected officials who benefit from the oil and gas produced in the Permian Basin but who don’t have constituencies out here that supporting what goes on in the Permian Basin supports the entire state,” Shepperd explained.
With committee members now appointed, the pace of bill filings will increase significantly. However, as of the first of February, multiple bills were already on the radar of industry supporters:
HB 206, a state version of the National Environmental Policy Act called the Environmental Review Act, and SB 186, a bill that would change the penalties for violations under the Oil and Gas Act, are already garnering attention among lawmakers.
Along with tax bills that are in the works, the PBPA will keep a close eye on the governor’s plans for an aggressive renewable portfolio standard, meaning an increased production of energy from renewable sources, including wind and solar.
“We are watching to see what impacts such a standard may have on electricity costs,” Miller stated.
Multiple bills were filed early that touch the oil and gas industry, including:
SB 59: enumerating lawful use of images taken by unmanned (drone) aircraft, including electric or natural gas utilities for maintenance, air quality sampling, oil pipeline safety and protection, and many other uses.
HB 223: would amend the state Health and Safety Code, allowing funding through greenhouse gas emissions fees of energy efficiency programs administered by certain utilities. The bill also would amend the Utilities Code to allow for “targeted low-income energy efficiency program[s]” as part of energy efficiency goals.
HB 225: appears to broaden the rules for air quality permits issued by the Texas Commission on Environmental Quality (TCEQ) and require deeper analysis of permits, while also tasking the TCEQ with a report by Jan, 1, 2020, (on which it may collaborate with the Railroad Commission) about improved regulatory approaches to “preventing air emissions from oil and gas equipment,” including compressors.
HB 42 and House Joint Resolution 13 are both aimed at “allocating a portion of oil and gas production tax revenue to the counties from which the oil and gas originated and to the use of that revenue.” A severance tax trust fund would also be set up for each county, administered by the state comptroller, with each county’s share equal to the oil and gas production borne by each county, with money to be used for road and bridge construction and maintenance where “impacted by oil and gas exploration and production activities.” HB 42 is to be administered if a constitutional amendment to do so is enacted by the 86th Legislature (see below).
HJR 13 is a proposed amendment to the Texas Constitution which would authorize HB 42 and add the following language: The legislature by general law may allocate a portion of oil and gas production tax revenue not otherwise allocated by this constitution to the counties from which the oil and gas originated to be used solely for the purpose of supplementing construction and maintenance of county roads and bridges that are impacted by oil and gas exploration and production activities.
How You Can Help
“PBPA members have already been a tremendous help to the PBPA staff and leadership in preparation for both sessions in Texas and New Mexico,” Shepperd shared. “As the sessions continue, we will continue to keep our membership and board up to date on issues that could impact the Permian Basin through our newsletters, other emails, and our membership luncheons.”
As far as further help, PBPA members will have the opportunity to come to Austin and Santa Fe to meet with House and Senate members, and as specific bills are filed and testimony is scheduled, the PBPA will ask members to come testify in committee.
“Our staff frequently testifies before multiple House and Senate committees, giving a much-needed voice to our members’ interests, and in doing so keeps our state lawmakers informed on the effects their legislation would have on our industry,” said Shepperd. “Members of the Legislature appreciate hearing from industry experts on proposed legislation.”
In addition, the PBPA will be hosting its annual PBPA Day in March; the exact date will be set as the Texas session progresses.
Those who are unable to make the trip to the Capitols can still play a valuable role in the legislative process by keeping apprised of emerging issues and communicating industry concerns and perspective to senators and representatives.
Colin P. Fenton is a leading light among an emerging coterie of thinkers who are not drinking the anti-fossil fuel koolaid. His thoughts shared before the PBPA give hope for a reversal of public opinion, however far away that might be.
A few days after Colin P. Fenton delivered a resounding keynote address at the Permian Basin Petroleum Association’s annual meeting, he was fielding questions from Permian Basin Oil and Gas Magazine about his talk and about the reception he received in Midland. Among those questions was an inquiry as to how an audience of Permian Basin oil and gas professionals presumably differ from an audience he might typically face somewhere else
“It’s easy to speak with the members of the PBPA. They know the oil and gas industry cold. They are also among the warmest, kindest, most humorous, most inquisitive, and most ethical human beings I’ve ever had the pleasure to meet in a quarter-century of travels to the far corners of the world. In some venues, my audiences may be antagonistic toward hydrocarbon production and use. But to be fair, my experience has been that if the research is thoughtfully-framed, based in fact, and presented calmly, logically, and honestly, anyone’s mind is open to instruction and change.
“For example, I gave the keynote speech at the 2017 Sustainability Conference of The Conference Board. That audience included more than 75 Chief Sustainability Officers (CSOs) drawn from the S&P 500. Many had vested professional incentives to avoid or reject oil and gas focused research content. But after my remarks, many approached me in the hallway to ask questions, share business cards, and inquire about getting more access to my research.”
Such a reply is characteristic of Fenton, a witty, articulate, well-versed analyst whose independent research into oil and gas realities has led him away from the party-line politics and even “propaganda” (Fenton’s word, and others’ too) pushed by today’s green lobby in its war on fossil fuels. Fenton’s address to the PBPA was, in fact, titled “Hydrocarbons Boom in the Age of Folly and Hammers,” a play on the idea of Soviet propaganda from the early-mid 20th Century. (See accompanying image.) His refreshing rebuttals of much of what gets fed to a largely unquestioning public sparked hopes that someday, perhaps, the tide will turn and fossil fuels will come into their own in the public eye.
Comparing his October visit to the Basin with the visit he made here three years prior, just as the downturn was beginning, Fenton told members of the PBPA: “I have to admit, it takes my breath away to see how successful you have all been… I did not anticipate that we would have the Permian now producing 3.5 million barrels per day.”
Fenton:“The members of the PBPA know the oil and gas industry cold.” Healso remarked that PBPA members “are among the warmest, kindest, most humorous, most inquisitive, and most ethical human beings [he’s] ever had the pleasure to meet in a quarter-century of travels to the far corners of the world.”
Remarking on Fenton and his talk in October, PBPA President Ben Shepperd had this to say: “The PBPA has always worked to share the most accurate and factual information available to our membership to help them make informed decisions. Much of that work is in the legal, legislative, and regulatory arenas, but economics drives it all. We are fortunate to have someone as knowledgeable as Colin who is willing to share his insights with us to help us better understand the constantly changing economic dynamics of our industry.”
Constantly changing. That is indeed descriptive of the attacks leveled at oil and gas in these tumultuous times. Fenton told PBOG that the propaganda spewing from legal and policy circles has suffocated the public’s hearts and minds. As is typical of propaganda, there is a chameleon quality to it—with the party line changing as false claims are defeated and hidden agendas are exposed.
Much of the attack leveled against oil and gas is packaged as “science,” but Fenton is not buying what they’re selling.
“It’s bilge masquerading as science,” Fenton said. “I have been stupefied by the speed with which vacuous concepts such as ‘fossil free,’ ‘carbon bubble,’ and ‘stranded assets’ have been created, sold, and accepted as dogma. All this has happened in the salons of Manhattan, San Francisco, and Cambridge within just the past five years, thanks to deep pockets of political and financial backing. That such demonstrably flawed postulations have passed unchallenged as incontrovertible fate proves the public is not paying sufficient attention. It’s disheartening to anyone who grasps the big picture and the creative problem-solving powers of technology and the capital markets. Worse, some of the promoters of these trendy views—when sufficiently badgered by a research analyst in a private setting—will make light of the chicanery afoot with the excuse ‘it’s just politics.’ ”
The good news, though, is that inevitably the oil and gas industry eventually will be understood in a different light. That light is called ‘science.’”
Real science, not concocted or imagined “science.”
The “folly” of Fenton’s title is seen in that “bilge” that he mentions. When he opened his talk in Midland, he cited his “folly and a hammer” theme for his talk.
What are follies? They are “political posturing, investment policy confusion, and regulatory mistakes,” among other things. What are hammers? Hammers are “fierce corrections wielded by the invisible hand, the market hand, and the regulatory hand,” among other forces. (See chart for more.)
“I’m going to argue that one way to look at oil and gas and all of the derivative products is to understand that our civilization is wrestling with many follies—ideas that may be partly out of touch with reality or severely out of touch with reality,” he said. These ideas are pushed upon the public, and they are directed most pointedly at the public that resists the message. The party line is wielded as a way of “punishing” the unconverted.
“They punish you when you get too ‘arrogant,’ too ‘dogmatic,’ when you don’t listen to the world,” Fenton said.
And much of this punishment is leveled in the name of science. But the irony, as Fenton keeps pointing out, is that the science and the “research” directed against the green lobby’s targets is sadly lacking in substance—and in many cases is mere made-up allegations.
“If you start claiming the mantel of science, but you don’t actually pay attention to material science, you’re not talking about science,” he said.
Besides science, there is the even more mundane world of just everyday fact. And everyday facts get lost, apparently, in these days when political objectives trump realities.
Fenton offered a fact that is too-little noticed:
Electric cars are fabricated from gas-based feedstocks and other hydrocarbons.
He counterpointed that “demand” fact with a “supply” fact. The fact that deep lakes of liquid methane (LNG) dot the surface of one of Saturn’s moons, Titan. He offered an actual photo of the lakes as proof. And his point was this: are we to believe that there were once dinosaurs roaming Titan? If not, what does that say about the potential sources of hydrocarbons in the universe, and even just here on earth?
Why this existence of hydrocarbons on Titan matters is because the propaganda that is spread by oil’s naysayers is that oil and gas come exclusively from “dinosaur remains,” and when that very-finite fossil source is exhausted, so is all oil and gas activity, and so is all oil and gas productivity—and the energy derived from it. The “dinosaur” motif, propagated by oil itself when Sinclair trotted out its “Dino the Dinosaur” symbol in the early 20th century, has not been good to oil and has become a weapon used against it by oil’s enemies.
But there are more hydrocarbons in the ground than could ever have been the result of decomposition of dinosaur remains. And there is more to hydrocarbons than just energy—just fuel. There is a world of products created from hydrocarbons, and without those products, we’d live impoverished lives, thrown back to civilizations utilizing mainly “leather and wood,” as Fenton put it, for most of our implements and products.
“Without hydrocarbons, Tesla’s sedan, and Tesla as a company, ‘blink into nonexistence, in a poof of irony,’” Fenton said, employing one of his patented Fentonisms. “They’re gone. The chassis is made of thermal plastics. The tires—synthetic rubber. There are adhesives and other products throughout the vehicle. And don’t mis-hear me. I am not attacking electric vehicles. I can show you that there is a place for electric vehicles and natural gas vehicles and fuel cell vehicles, and it would be a folly to just throw up your arms and say I don’t need to worry about [or can’t use] those.”
What these charts have in common (as is explained in the text) is a dip in 2016 that may have been indicative of a recession that economists failed to identify.
Fenton had much more to say about current conditions in his nearly-hour-long talk that seemed 15 minutes long. And while we must pass over his remarks about the markets, about the Paris Accord, about the periodic chart, about emerging world demand and other topics, we have space for just this remaining discussion of the economic cycle.
Fenton posited that maybe, just maybe, the United States experienced a recession, even if only an “invisible” recession, and about two years ago, and if he is right about that, then much of the handwringing in the current market about an impending recession is misplaced.
“It’s true that the yield curve of the United States has begun to get to scary levels that have preceded recessions,” Fenton allowed, “but it’s actually been bouncing back since late August. I’m going to give you a contrarian idea here. Most of my peers in markets would tell you that a U.S. recession is highly likely within the next 18 months. Most people really believe that we’re late in the cycle, and we’re due for a recession.
“[But] those are the actual industrial production statistics of the United States,” he said, referencing the statistics shown in the chart reproduced on this spread [see figure tktktktk]. “They actually already contracted in ’15 and ’16, so it is not arguable that the United States had a manufacturing recession already, several years ago. In fact, I went on Bloomberg TV, and I said I could view the United States [then] as being in a recession, and the host nearly fell out of her chair. She was like, ‘That’s a ridiculous thing to say. How could you be a professional forecaster, and say that?’ And yet, I repeated it in my research on September 24th this year. Five days later, the New York Times took that idea and published it. So what’s my point? My point is, a lot of the forecasters are beginning to say, “If I look at statistics… ”
He looks at statistics with us, pointing to the trend shown in the graph at lower right [same figure]. “Bottom right, trade already collapsed,” he said. “Those are the exports of the United States, and in the late second term of Mr. Obama’s administration, they actually contracted for many, many months, and they’ve been positive in the Trump administration. Those are just facts. Is that a recession? What do we call that? On the middle, bottom panel, those are retail sales. If it were not for Amazon, the U.S. would have had negative GDP in the first quarter of 2016. One company’s 30 percent growth rate in retail sales saved the entire U.S. GDP.
“So, I continue to hold to the idea that the next recession is maybe four to six years away, and so you may be about to see a boom,” he said, introducing a brighter note. “If you thought last year was a boom, wait until you see what happens over the next few years if that [conclusion] there is correct, because we’re going to have something like one and a half to 1.7 billion cubic feet of coal demand growth. U.S. petroleum exports have already doubled since the start of the downturn are going to continue to gather apace.”
And finally, this:
“The crude spreads that had been problematic for you, may still be problematic, but I think will get resolved with capital expenditure. As for pre-refinery utilization, before 2017, it was above 95 percent only 8 percent of the time. Today, that’s a third of the time. I can use some clever math to try to guess what your pipelines’ utilization rates are? Punchline is 99 percent, and that’s why you’re seeing the differentials that you’re seeing.
“And [that’s why] when I look at [the question of] why is everybody so worried right now—it literally looks to me like a circular firing squad.” [laughter]
The Permian Basin oilfield housing/hospitality sector keeps on building.
By Paul Wiseman
“There’s no place like home,” was the mantra prescribed to transport Dorothy back to Kansas. For shift-working Permian Basin oilfield workers from Kansas or just elsewhere in Texas, they’re away from home so much they may not know what home is. But there’s a need for a home of some sort when they’re working that shift. With weeks-on/weeks-off rotations the norm, housing those workers has become a billion dollar industry. From sector leaders like Target Lodging to go-getter entrepreneurs with a few homes to lease to executives, temporary housing has become—pardon the pun—a cottage industry of its own.
Target recently entered into merger agreements with Platinum Eagle Acquisitions Corp. and RL Signor Holdings LLC to form “the largest provider of specialty rental accommodations with premium catering and value-add hospitality services in the United States,” according to a company press release.
Housing and hotel markets in the Permian are stretched to the breaking point, and the casual observer might think this creates even more need for oilfield solutions. But Target’s CCO, Troy Schrenk, says his company doesn’t compete directly with houses or apartments.
“When we think about the workforce in the Permian Basin, they’re largely on a rotational basis, and the customers that we support are really looking for a provider that can give care, food, hospitality, and services the other 12 hours [in which] their employee is not working for them. That’s where it’s different” from the home purchase market.
Specifically, housekeeping, food, and activities are part of the need for rotational workers. “It’s a hospitality program that’s designed specifically for this type of workforce,” Schrenk continued.
The remoteness of many area wells does play a part in housing opportunities, “given that it [the Permian] is almost the size of the United Kingdom, [yet] with a population of less than 500,000.” Target has about 9,000 beds in 15 communities in the Basin as a whole, with almost 3,000 of those in the Midland-Odessa MSA. There are two communities in Odessa and one in Midland.
When the business combination is completed, the merged company will have 13,000 beds in 22 communities, all in the United States. A little math shows that the great majority of Target’s beds lie in West Texas.
Part of the company’s goal in choosing their locations is to economize workers’ travel time. “We’ve established a network of communities that cover the south [Permian Basin], all the way to the north up into Carlsbad—to the east, to Midland, then all the way out west to Pecos, Mentone, and Orla, and Big Lake, in the Rankin area, to Barnhart,” said Schrenk. This allows companies to move employees from community to community as their work locations change.
Schrenk noted that their Basin business was strong even during the downturn of 2014-15, while other areas such as the Bakken and Eagle Ford suffered. In 2018, he said, there’s renewed growth in the Bakken and elsewhere.
Workers are now coming from all over the world, said Schrenk, which was not the case in the 2012 boom. And there are other demographic changes in the works. Up to 20 percent of the workers staying in Target’s facilities are women, and about 24 percent work for the government instead of in the oil patch.
In many places, they also provide stand-alone services apart from lodging. These include site and hospitality services such as facilities and property management and food. “It’s just a natural part of what we do, and there’s pretty robust demand for those stand-alone services, even without the lodging,” he noted.
The company looks for continued growth in the area, with Schrenk commenting, “I still think it’s the early innings of that basin, especially when you start seeing some of the long-term investments that the supermajors and majors are making there, and they’re really just getting started.”
Not lost on Schrenk was the irony of saying that a region that’s been producing for more than 90 years is “just getting started,” but regarding the unconventional revolution, the point is well taken.
There are other companies meeting other housing needs as well. For executives, a stay at a large-scale workforce housing unit would be rare—mainly because executives generally spend more time in the in-town office than in the field. Accommodating management people for a few days to a couple of weeks is the goal of Miotracasa’s Janie Snelson and business partner Kim Womack, who own two homes—one is a two-bedroom, the other is a three-bedroom—that they lease out. Snelson and her husband, Steve, own two other executive rental homes apart from Miotracasa.
Though Miotracasa currently does their leasing through AirBNB, they’re looking to move toward leasing directly to corporations. AirBNB allows them to make rate adjustments to find the perfect balance between occupancy rates and customer value. “We’re trying to reach the perfect utilization to make the perfect profit while keeping within the rental ranges of [clients’] own company guidelines.”
Their target market is “the executive who travels, and travels every week—they want this. We also do concierge shopping for them if they need it,” Janie Snelson explained.
To that end they carefully choose neighborhoods in which to acquire properties, maintain an executive-level décor, and offer high-end services. Janie added, “We would like people to walk in and feel like it’s their house, that it’s taken care of, that they can trust us. We offer more.
“Nine times out of ten, we’re leasing to CEO/company owners —I don’t think we’ve deviated from that at all.”
Noted Steve Snelson, “We’re interested in people that can manage themselves, and the properties are at that level.”
The trust/repeat factor led to the choice of name for the company, she said. “The reason we named it Miotracasa [‘my other house’ in Spanish] is that guys were always calling and telling us, ‘Hey, somebody’s going to be there on Saturday or Sunday, would you have your housekeeper clean at my other house.’ That’s where the name came from,” said Janie.
After buying the first house in May and beginning to lease it in July after completing renovations, they’re already getting multiple repeat guests.
For the future the Snelsons and Womack are looking to expand, by buying “houses that have good bones, that are easy to fix [and to] hold for the future. We love our houses.”
Which at some future point will present a challenge in staffing up to keep up with cleaning and maintenance. Currently they and a few close friends do the majority of the cleanup during occupancy turnover. This requires a lot of in-town time. Steve Snelson noted that they are training associates who could take over some of the work as the inventory grows.
Have there been surprises in this undertaking? Janie reported the biggest surprise as being “The fact that guys will sleep anywhere, they don’t care, they just want a roof. One company, coming in for an industry event which caused all hotel rooms to be filled up, wanted to crowd several guys into one home, but Snelson talked them into spreading into both houses because Miotracasa limited the headcount in each house.
The best part, said Steve: “It’s the hospitality aspect of this, we actually both like it.”
Major providers whose bed counts range in the hundreds and the thousands need someone to build those largely modular units. In 2018, Oklahoma-based mobile home builder New Vision Manufacturing saw an opportunity to adapt what they were already doing for entry into this market. Later that year they opened a factory in Breckinridge, Texas, to build units for sale in the Permian and other Texas basins.
Managing Partner Kyle Williams had been in the mobile home finance business since 1990. At one point he also ran 90 mobile home parks in eight states. He then started RGN Services to provide new and used inventory to the oil and gas industry and to mobile home park owners.
Another partner had been providing onsite mobile production unit housing for drillers and geologists for a number of years. This partner had begun building his own units two to three years ago at a factory in Oklahoma.
In early 2018 a large factory space in Breckenridge became available and about the same time the two investors located an experience factory manager to run the day-to-day operations. They began building units in Breckenridge in November of that year.
Initial orders were for 110 units headed for the Permian Basin, getting the factory off to a strong start.
The Breckenridge plant’s Assistant General Manager, Jeff Baker, says the location employs about 70 people, some of whom drive from as far away as Abilene. The small workforce in Breckenridge allows New Vision to pay a competitive wage without facing the rising pay scales they would contend with in Midland/Odessa, but it does mean reaching out beyond Breckenridge to fill their ranks.
The factory is 136,000 square feet, which Williams says makes it the largest manufactured-home factory in Texas. “We were extremely fortunate to get our hands on this facility, for sure,” said Baker.
While they’re willing to build anything from tiny houses to production units, their main focus is on four styles of production units for drilling contractors and “man camp units—that’s the 100 units we’re building right now,” said Williams. “They’re either 18 by 80, 6-bed, 6-bath or 5-bed, 5-bath, with a utility room for washers, dryers, or 5-bed, 5-bath with a full kitchen.”
The minimum order for custom builds would be 5-10 units.
In the next few years Baker looks for strong growth in the company’s four main target areas: oil and gas, tiny homes, units for street dealers, and manufactured housing. “I think our goal is to be at about 180 employees by next summer at this location,” he said.
This is further proof that the huge growth in the oil and gas industry in the last 10 years has provided fertile ground for an expanding array of support industries, creating more and more jobs in its wake.
Here’s how Schlumberger’s Glossary defines a “fish”: Anything left in a wellbore. It does not matter whether the fish consists of junk metal, a hand tool, a length of drill pipe or drill collars, or an expensive MWD and directional drilling package. Once the component is lost, it is properly referred to as simply “the fish.” So much for definitions. What follows is the rest of the fish story.
by Bobby Weaver
Oil patch fishermen are a special breed. The fish they seek live deep down in the earth and require specially designed gear to coax them to the surface. The fish oil patch fishermen seek are not live creatures at all, although some might disagree because of their uncanny ability to evade capture. No, oilfield fish are items lost downhole in oil wells and the fishermen are those specialists who remove them from their environment.
Beginning with the 150- to 500-foot oil wells of the 1850s and continuing to those technologically sophisticated 20,000 foot projects of today, one of the most consistent oil well drilling problems has remained how to retrieve unwanted items lost down the well bore. Whoever first called those lost items “fish” or called those who retrieved them “fishermen” has been lost to history. But regardless of how those terms originated, it is acknowledged by oil men everywhere that the unique skills needed for fishing are earned through long experience by persons with the rare ability to visualize what is happening thousands of feet below the surface. That combination of experience and skill is necessary because every fishing job is different, often requiring specially fabricated tools ofttimes created on the spot and possibly used only once.
Fishing [requires] long experience by persons with the rare ability to visualize what is happening thousands of feet below the surface.
In the very earliest days of the industry the drilling was done exclusively with cable tool rigs. It is known that they suffered numerous fishing problems but there are very few descriptions of the tools they used. It was not until 1884, with the publication of the Oilwell Supply Catalog of that year, that the first known illustrations of fishing tools came to light. Those listed in that catalog were considered standard devices used for common problems encountered in the retrieving items lost in the hole. There is little doubt that those standard tools were the result of thousands of predecessors created in local machine and blacksmith shops throughout the oil patch during the preceding decades and abandoned once the fishing job was completed.
Although designated as standard fishing tools, the items sold by the various supply houses such as Oilwell were not by any means used exactly for the specific purpose for which they were advertised. Many of them were modified on the job to fit the particular problem presented. By far the greatest problem encountered by the cable tool rigs involved lost manila rope or steel cable drilling line from which was suspended the drilling string. When one of those lines broke or for whatever reason got lost down the hole it had to be fished out. The most common tool used for that purpose was a spear.
The barbs captured the line as the spear was withdrawn.
The simple fishing spear was just what its name indicates. It was a long shaft from three to ten feet in length with a series of barbs welded to its sides facing toward the top of the tool. When the spear was lowered into the tangled mess of a broken drilling line at the bottom of the hole the barbs captured the line as the spear was withdrawn. Sometimes the single shaft spear would not grasp the lost line tightly and it slipped off the barbs. In that case there were spears featuring two or possibly three shafts arranged in a circle with the barbs welded to the inside of the circle in order to get a better grip and prevent losing the line through slippage.
Other implements for handling lost lines were the knife and the hook tools. The hooks worked similar to the spears only they were shaped like a fishhook. The knives on the other hand were simply designed to cut the drilling line in case it was so entangled the spears could not pull it out of the hole. Sometimes a combination knife and hook tool was used so the line could be grabbed by the hook and pulled to the inside of its bend, where there was a sharp cutting edge. Once the line was cut away from the tangled mess it could be fished out of the hole in smaller lengths. Also sometimes the drilling string became stuck fast, in which case those cutting tools were used to shear the drilling line as close as possible to the drilling string so a whipstock could be set to drill around the offending items.
Other implements for handling lost lines were the knife and the hook tools.
Beyond drilling line retrieval tools there were a variety of grabs utilized to remove various cable tool items lost downhole. In the case of a string of tools lost but not stuck beyond removal there were several overshot tools that could be lowered over the string and when pulled upward would tighten around the jars—or whatever the top lost tool was—and pull the string out of the hole. Then there was the bailer grab, which was simply a tool similar to a two pronged spear without the barbs. At its bottom was a hinged pin that, when lowered over the bail of the bailer, would swing open and once past would drop back and latch into place, allowing the bailer to be withdrawn from the hole.
Those then were the basic tools used for fishing cable tool wells, along with a host of variations. They were all simple, common sense solutions developed over the years by hundreds of unheralded drillers, tool dressers, and a variety of other oilfield hands. As already mentioned there were literally thousands of variations on those basic tools all designed for problems encountered as well as to suit the particular inclinations of the fishermen who employed them.
When rotary rigs entered the mix about 1894 the downhole fishing problems tended to change somewhat with the advent of the new technology. The lost cable problem practically disappeared with the advent of the rotaries due to their using pipe instead of cable, but the numbers and variety of items lost downhole was absolutely amazing. They ranged from a roughneck simply dropping a wrench in the well bore to bit cones being broken off or maybe the drill pipe being twisted off.
The driller told the roughneck he was fired. The roughneck looked the driller in the eye and pitched the [fished-out] tool back into the hole.
It is from those types of incidents that have fostered some of the best illustrations of oilfield culture. For example the story of the boll weevil who dropped a wrench into the well bore that resulted in a five day fishing job. When the battered tool was finally retrieved the driller handed it to the hapless hand and proceeded to give him a real oil patch dressing down. When he was through the driller told the man he was fired, whereupon the roughneck looked the driller right in the eye and pitched the tool back into the hole. Some say that indicates the graduation from boll weevil to hand, but I can guarantee you it would cause a fistfight right then and there on the rig floor. Then of course there is the term “twisting off” in regard to accidentally severing the drill pipe. That term has come down over time to describe anything a hand might do to cause him undue grief, usually things involving imbibing large quantities of alcoholic beverages.
But I digress. Back to the subject at hand of fishing on rotary jobs. One of the most frequently utilized tools, at least in those early days, was a device called a junk basket designed to remove small objects lost downhole. A junk basket was constructed by cutting slender fingers in the sides of a piece of pipe, fastening it to the drill pipe in lieu of a bit, and lowering it into the hole until it touched bottom. Then the pipe was slowly rotated and weight gradually applied to the drill string. The weight increase and rotation caused the fingers to collapse inward and hopefully clutch the fish within its grasp. Over time that crude device was engineered into a more sophisticated tool, causing it to remain an important fishing tool for many years. In later times powerful magnets were sometimes attached to the bottom of the drill pipe in an effort to remove small items lost downhole.
The most serious of the fishing jobs, like those of the cable tools, revolved around lost suspension devices, which in the case of rotaries was drill pipe instead of cable. In the case of stuck pipe, either drill pipe or casing that could not be withdrawn from the hole, it might be necessary to save as much of the stuck pipe as possible. In the very earliest days that was accomplished by a nitro shooter lowering a shot inside the stuck pipe and shooting it apart. Or a device called a cutter could be lowered into the hole and actually cut the pipe apart. In either case the well might be saved if, after the severed pipe was removed, it was feasible to back uphole a little ways and use a whipstock to deviate the hole enough to bypass the stuck pipe. Otherwise the well was simply abandoned and at least some valuable pipe was saved.
Powerful magnets were sometimes attached to the bottom of the drill pipe.
The problem more often associated with lost pipe is that it is twisted off at some point downhole. In that case it is never certain what sort of situation exists at the bottom of the hole in regard to just exactly what is sticking upward for the fishing device to grasp. It might be a jagged piece of pipe, it might be a smooth surface, it might be leaning one way or another, it might be open, it might be collapsed, or whatever. So an important aspect of the fishing process is to discover what is the exact disposition of the object, which in turn will help determine the type of tool needed for the job.
Sometimes a heavy lead plug is lowered into the hole to get an impression of the nature of the top of the fish. If it is retrieved and the fish is shown to be all ragged and bent and generally a mess, as is often the case, it is possible to lower a special tool to grind the item down to a manageable size. When it is reasonably clear what the situation is, there are a variety of tools that can be utilized. They generally fall into the category of undershot or overshot in nature. That is, the undershot, which is lowered inside the offending pipe, or the overshot, which is lowered over the outside of it. Once in place those items have a variety of grabbing mechanisms to grasp and hold the pipe while it is removed from the hole.
Regardless of the exact nature of oilwell fishing jobs, two things are certain. First they normally take a long time. At the least a few days and some of them stretch into weeks. The second thing is that shutting down a drilling operation is an expensive operation and the least amount of time it takes the better. Hence the value of a good fisherman who can figure out what is going on way down below the surface.
A range of factors can restrict casing ID and prevent a successful completion. Higher build rates, complex trajectories, and longer horizontal sections pose considerable challenges to casing integrity. Although careful casing and borehole trajectory design and appropriate drilling and completion techniques can reduce the risks, they cannot eliminate them. In addition, the constant pressure to lower well costs has resulted in abandoning practices such as drift runs prior to frac operations.
A solution that has proven effective in overcoming casing integrity issues and keeping operations online has been the deployment of extended-range frac plugs.
“The extended-range frac plugs have a smaller OD, which enables them to pass through the restriction and subsequently expand to the standard casing ID,” said Nick Pottmeyer, Vice President of US Completion Tools at Nine Energy Service. “As a result, they keep operations moving in damaged and repaired wells and eliminate the worst-case scenario of having to abandon the well because of a restricted ID.”
Certain design considerations enhance the applicability of these plugs and should be taken into account for optimal results.
“For example, a molded element system with a smooth surface devoid of rough edges or protrusions lowers the risk of the plug presetting or getting stuck while running into the hole, enabling faster run-in speeds,” said Pottmeyer. “Design features that reduce the risk of element flaring during deployment also expedite run in.”
In addition, the plugs should be designed to be easy to mill out once the fracturing operation is complete because casing ID restrictions necessitate use of a smaller mill. Compact composite plugs with ceramic button slips reduce millout time to just a few minutes per plug. These materials also reduce debris size, so that cuttings are easily circulated out of the well, facilitating cleanup.
The slip design of the extended-range plugs should also be taken into account. The slips must provide secure anchoring in hardened casing (i.e., ICY grades). Once the slips are milled out, the milling assembly pushes the lower end of the frac plug down onto the subsequent plug. Design features that prevent the plug end spinning on top of the next plug are important for efficient millout.
The Scorpion Extended-Range Frac Plugs from Nine Energy Service possess these unique design features that are critical to success and more. Able to withstand expected bottom hole temperatures (300 degrees F) and high-pressure frac operations (10K PSI), the Scorpion Extended-Range Frac Plugs are available in a range of sizes and have the flexibility to deploy on wireline or coiled tubing, which expands the operating envelope.
“In addition to supplying the extended-range plugs, our wireline team also provides modeling software so that the operator can see the details of the wellbore and restriction before plugs are run to help optimize run-in speeds and pump down rates,” said Pottmeyer. “In regions like the Permian, where tortuous wells are common, this modeling can make the difference in achieving a positive outcome.”
To learn more about how Nine Energy Service can help you to overcome casing integrity issues and keep your operations moving, please visit nineenergyservice.com/extended-range.
What’s going on? Less than 4 months ago in early October, WTI was $77/B and some international banks and trading houses said it was going to $100/B! Just over 2 1/2 months later, on the day before Christmas, WTI had fallen to $42/B. The Wall Street Journal kept saying it was all because of a glut in supply, which suggested strongly to the reader that WTI would go even lower.
For producers in the Permian, the joy of the holidays was tainted with uncertainty, anxiety, and confusion. Oil prices do have a long history of volatility, with wide, event driven swings during the course of a year. But at the end of the day, WTI reflects the fundamentals of supply and demand and how they are changing.
For readers who need or want an informed, independent perspective on the major underlying forces driving changes in oil prices a subscription to Boston Energy Research’ monthly road map of future oil prices could be very helpful and make a big difference.
See for yourself: The headline of its December road map read “WTI Oil $67/B in 2019” with the following synopsis: “With the OPEC cut announced last week, the oil market will remain in balance through 1Q19. The recent correction was overdone. The market dynamic changes in 2Q19 and upside price volatility could be explosive.”
WTI was $53/B on December 14th, the day the report was published, about where the price of WTI is now. Boston Energy Research anticipated a $59/B price for the first quarter of 2019 based on its December analysis of underlying fundamental trends.
The road map is published monthly promptly after an analysis of the latest data published by the IEA, OPEC, and other sources.
To subscribe to the Road Map, which publishes every month but appears in full in this magazine only once every three months, email firstname.lastname@example.org and ask for pricing information. Please use the subject line “Oil Price Road Map.”
With the OPEC cut announced last week, the oil market will remain in balance through 1Q19. The recent correction was overdone. The market dynamic changes in 2Q19 and upside price volatility could be explosive.
WTI is $53/B, near a 14 month low below $50/B the end of November. Without a geopolitical surprise, a 2019 WTI average around $67/B is anticipated, up from a probable $65.50/B average in 2018 and $51/B in 2017.
Brent fell to $57.50/B and is now $61/B. It is projected to average $72/B in 2018 and $73/B in 2019, $6/B higher than WTI. It was $54/B in 2017, with a $3.10/B premium over WTI, in line with historic spreads.
Oil prices typically respond to anticipated changes in inventories compared to historic norms for that time of year. Monthly OECD inventories calculated by the IEA and OPEC are followed closely. Measured against the latest 5 year average, they are a key indicator of the health of the oil market. The OECD represents 48% of global demand. To illustrate the point, a peak surplus of 385 MMB in 1Q16, which was 14% larger than the 5 year average at that time, caused the 70% crash in oil prices to a low of $27/B from an average over $90/B in 2014.
WTI averaged $70/B in 3Q18, with a $5.50/B discount to $75/B Brent. Since then, fear of an oversupplied market drove prices substantially lower.
OPEC estimates OECD inventories increased from a 25 MMB deficit to the 5 year average in September to a 22 MMB surplus in October. The IEA calculated a 15 MMB October surplus.
Exports to China would have made a big difference
There was another good reason for the decline in WTI. Since mid September US crude oil inventories also increased. Over a 10 week period they steadily increased by 62 MMB to 6% above its 5 year average at the end of November and at the end of the fall refinery maintenance season. Refineries operated at reduced rates over a 9 week period, while US oil production continued to increase (up 640 MBD from September), which overwhelmed only a modest decline in net crude imports. The US crude surplus is largely on the Gulf Coast. Over the same period, US gasoline and distillate inventories declined 20 MMB. And since the end of November, US crude inventories declined 9 MMB with an increase in exports to record levels 2 weeks ago.
In response to the fear of new tariffs on oil, exports to China fell to 0 in October and November. They peaked for the year at 533 MBD in June. Had they remained at the June level, US oil inventories at the end of November would likely have been close to the 5 year average. While not assumed, China is likely to nudge state owned refiners to increase US crude imports as a gesture of sincerity in coming trade negotiations.
Oil inventories were supplemented in October and November when the US sold 11 MMB of crude oil from its Strategic Petroleum Reserve, which is part of a program to fund needed maintenance. The DOE is required by Congress to sell 290 MMB starting in 2017 through fiscal 2027.
While oil inventories in the US were high, crude oil holdings in Europe were below the 5 year average, and well below in the Asia Pacific region after reaching a historic low in September.
Bearish market psychology is extreme and unwarranted
With the 500 MBD cut in December announced by Saudi Arabia in early November, the 22 MMB October surplus in OECD inventories to the 5 year average (a surplus less than 1%) will remain unchanged at the end of this year.
But with the $27/B correction, the market instead was focused on 1Q19. The Wall Street Journal warned last week that an OPEC cut was needed “to mop up a burgeoning supply glut”.
The fundamentals are quite different. Without the cut that OPEC, Russia, and its allies announced last week, OECD inventories would have increased 69 MMB in 1Q19 to a 62 MMB surplus in March — a sizable seasonal swing but just 2.4% larger than the 5 year average.
Sentiment is a powerful short term force which even OPEC recognizes and respects. But ultimately it gives way to fundamentals which unavoidably are the main oil price driver.
1Q19 outlook for prices: $59/B WTI, $67/B Brent
The cut by OPEC+ will result in a 9 MMB deficit in OECD inventories compared to the 5 year average in 1Q19.
OPEC agreed to reduce its production from October levels by 800 MBD for a 6 month period beginning in January. Saudi Arabia said its January production would be 10.2 MMBD, 450 MBD less than October. Excluding Iran, Libya, and Venezuela who are exempted, other OPEC members will cut their production by 2.5%. Total 1Q19 OPEC production will approximate 31.61 MMBD. OPEC estimates the call for its crude will be 31.67 MMBD.
Russia and 9 other non OPEC producers agreed to cut their production by 400 MBD. Russia will reduce its crude oil production by 228 MBD from 11.41 MMBD in October. It said it will take until April to reach its commitment because of `freezing winter and technical conditions.’
The 1.2 MMBD cut announced by OPEC+ will offset most of the sequential seasonal reduction in demand for OPEC crude. Global demand is expected to decline seasonally by 1.00 MMBD and non OPEC production outside Russia and its allies will increase by 455 MBD. The market will be sensitive to OPEC compliance.
With OECD inventories near the 5 year average, a gradual improvement in sentiment is likely to support a gradual increase in prices. A WTI price around $59/B in 1Q19 is consistent with fundamental sensitivities to changes in inventories, with a significant (maybe $8/B) premium for Brent. Sentiment is a huge unknown, but with demonstrated OPEC discipline, it is likely to be increasingly supportive as 2Q19 approaches.
In the lead up to last week’s meeting, OPEC producers expressed their desire for oil prices in the $70s (meaning Brent). They plan to meet again in April, with the possibility they may extend the cut for another 6 months, if necessary.
The dynamic changes in 2Q19: upside volatility could be explosive
With OPEC discipline, the deficit in OECD inventories to the 5 year average willbuild toa 77 MMB deficit in June (just over a 2% difference but sentiment made the current market hyper). That is 3x larger than the deficit in September when WTI was $70/B and Brent was $78/B.
World oil demand is expected to increase seasonally about 1.2 MMBD, substantially more than the 790 MBD increase expected in non OPEC production, while OPEC production declines 300 MBD to 31.31 MMBD in response to a continuing decline in Venezuela and Iran. OPEC estimates the call for its crude will be 31.77 MMBD. It is likely to be somewhat more.
Oil prices are likely to rally strongly in 2Q19 in response to a growing deficit, as it responded in 4Q18 to fear of a growing surplus. An increase in WTI prices to a $68/Baverage for the quarter would be consistent with sensitivities to changes in inventories. Bullish sentiment could magnify the increase further.
A $70/B WTI price is assumed as a working assumption for the rest of 2019, consistent with signals from OPEC producers. And with the market functioning smoothly and remaining in balance, it is logical to expect the Brent premium to slowly decline in 2019 to its typical $3/B premium by the end of the year.
Oil prices consistently have wide, event driven swings during the course of a year. There were 7 swings in 2018 with an average swing of $12/B between the high and the low.
The EIA currently anticipates a 2019 WTI price of $54/B with a $7/B discount to Brent. Its estimate was reduced substantially from its estimate a month ago and essentially unchanged from the current price. This suggests the risk in a change in sentiment is all to the upside. That would provide fuel to a price spike in response to a bullish event.
A rally could be tempered in 3Q19 by the looming surge in non OPEC supplies from mid/ late 2H19, primarily from the Permian Basin. But it also seems reasonable to expect OPEC will continue to adjust its production to keep the market in balance and avoid a spike in oil prices to unreasonable levels which would have a negative impact on global demand.
Recent oil price history
WTI reached a 14 month low below $50/B the end of November. On October 3rd, it peaked at a 4 year high nearly $77/B. The $27 correction began in response to signs of slowing economic growth in China, increasing tariffs on its exports, and weakening demand in other emerging markets in response to a Brent price in the mid $80s at the time. The decline in WTI and Brent accelerated when Saudi Arabia indicated it would raise output to 11 MMBD, 865 MBD more than it produced in 2Q18, and subsequent news the US would grant waivers to major importers of Iranian oil after previously indicating it wanted to reduce its exports to 0. Brent fell to $57.50/B.
As oil prices peaked in early October, traders had accumulated bullish long positions equivalent to nearly 1.2 bn B of oil. At the same time, short positions in the 6 most important petroleum futures and options contracts fell to the lowest level since at least 2013, which created a near record imbalance between bullish and bearish positions in crude oil markets. At the time, a number of international banks and trading houses anticipated a Brent price over $90/B by the end of the year, others expected a price over $100/B. Exuberance was high, the market was ripe for a correction.
By the end of November, traders cut their net long positions in Brent to 168,512 contracts, the lowest level since 2015 – which preceded the bottom in oil prices in 1Q16. The market is now oversold.
Primary trends causing oil inventories to change which causes oil prices to change:
Supply demand fundamentals have begun to respond to the $27/B price reduction in the last 2 months.
The IEA currently projects a full year world oil demand increase in 2019 of 1.33 MMBD to 100.6 MMBD, which is 667 MBD more than the growth in supply. OECD inventories will decline by 24 MMB after an increase around 37 MMB in 2018. OPEC anticipates a 1.29 MMBD increase in global demand. Demand increased 1.30 MMBD in 2018 and 1.73 MMBD in 2017.
While US stock markets are weak because of growing pessimism about economic growth and the trade dispute with China, the International Monetary Fund said last week that it “still had a strong growth forecast for next year for the US” and that it “didn’t see the elements of a recession”. The IEA relies on the IMF’s global economic forecasts to make its forecasts of global oil demand.
Global demand growth in 2019 could be stronger. Asian and emerging market currencies recovered sharply in November. The drop in oil prices will ease their financial burden from the cost of large oil imports and may reverse the recent slide in their oil demand.
Total global oil supply is currently projected to increase by 590 MBD in 2019, with a 2.51 MMBD increase in non OPEC supply partly offset by a decline in OPEC oil production of 1.92 MMBD.
The growth in non OPEC supply could be less. The shock of the recent oil price crash could cause producers to be conservative in their 2019 capital spending, while using cash flow to further improve their balance sheets. All of their budgets will be published by late January and February when they report earnings.
The drop in oil prices will also increase anxiety as to the adequacy of global upstream spending to provide ample oil supply beyond 2019. Schlumberger continues to warn a supply gap will emerge before 2025. A large increase in future oil prices is looming.
There is less industry appetite for exploration drilling. Rystad data shows there were only 1400 exploration wells drilled in 2018 compared to 4000 wells in 2013. Producers are prioritizing development and short cycle infill drilling, which is making future global oil supply increasingly dependent on US shale producers.
The impact of sanctions and waivers on Iran is still unclear. The consensus anticipates a 920 MBD production decline in 2019 following a 215 MBD decline in 2018 to 3.60 MMBD. Iran’s November production dropped to 2.95 MMBD.
US growth is explosive. Current trends indicate US production will increase 1.65 MMBD in 2019, while the rest of non OPEC outside Russia and Brazil declines 48 MBD.
US crude and liquids output increased about 2.03 MMBD in 2018 following a 778 MBD increase in 2017. It was 16.07 MMBD in November and will average about 15.22 MMBD for the year, comprising 10.87 MMBD crude oil and 4.35 MMBD natural gas liquids. It is expected to approximate 16.85 MMBD in 2019, with a 1.20 MMBD increase in crude oil and a 435 MBD increase in gas liquids.
Other key variables worth tracking to better understand the big picture and provide possible insights how it may change – and it will change:
In September, the President of Unipec, China’s primary crude oil importer for state owned refineries, cited long term plans to increase its imports of US crude oil to 500 MBD. It also leased 10 MMB of storage capacity in the US Virgin Islands to support its long term plans. Imports by China’s independent refiners will be additive. The absence of exports to China was a major ingredient in the sizable build in US crude inventories in 4Q18.
Saudi Arabia requires an $88/B Brent oil price to balance its 2018 fiscal budget; $58/B Brent was far from it. US policy to impose sanctions on Iran to reduce its revenues serves Saudi Arabia’s interest as well – all of which points to an optimum Brent price near $75/B to balance from a Saudi perspective.
Before it agreed to participate in the latest OPEC cut, Russia expected its 2019 production would be the same as the 11.55 MMBD it will produce in 2018. It has the capacity to produce 11.85 MMBD including gas liquids. In early October its oil minister warned that oil prices could rise further above $86/B `to the detriment of the global economy.’
Venezuela’s meltdown continues to get worse. Since 2006, it has received over $50 bn in loans and credit lines from China and at least $17 bn from Russia. It is obligated to repay its debts with oil. The 37% decline in PDVSA’s production since last year to 1.14 MMBD in November has reduced its compliance with its 464 MBD repayment requirement to China to 60% since January. It has only met 40% of its requirement to send 380 MBD to Russia. Theoretically, it will be obligated to send close to 90% of its 2019E production of 960 MBD to China and Russia just to meet its current debt obligations. Oil prices would spike if Venezuela totally imploded.
Venezuela’s production will be about 1.34 MMBD in 2018, down 628 MBD from 2017. An additional decline of 380 MBD is anticipated in 2019.
A major uncertainty in 2H19 is the rate of the ramp up in Permian Basin production when new pipelines are on line in 2H19. Total full year 2019 Permian liquids are tentatively expected to increase 750 MBD, although the increase could be larger. Only a minimal increase production is expected in 1st half, before a surge in the 2nd half when additional pipeline capacity of 2.03 MMBD will come on line. A 2nd pipeline wave will start up in 2020, adding 2.10 MMBD capacity or more.
The inventory of drilled but uncompleted wells (DUCs) in the Permian has steadily grown since 1Q16 and has now reached 3866, an increase of 58% since January. The number of DUCs in all other major US resource plays is up 4%. The EIA’s analysis of historic data indicates a normal DUC inventory for an oil dominant resource play like the Permian should currently be about 1100 DUCs. The current 2766 Permian DUC well surplus over the `normal’ level represents a 1.53 MMBD oil production backlog awaiting fracing and completion, with an additional backlog of 0.46 MMBD natural gas liquids.
When adequate pipeline capacity is once again available, it is uncertain how quickly producers and oil service providers will be able to complete the enormous DUC well surplus.
They have every incentive. Permian breakeven costs are among the lowest in the US at $31/B, with EIA data indicating a current new well production average of 595 MBD oil. Leading producers are getting much better results as they continue to improve well design and obtain further cost reduction through logistical efficiencies. In its 3Q18 earnings call, Chevron reported an increase in its 3rd quarter Permian production of 80% on year to 338 MBOED with the comment: “that’s the equivalent of adding a mid sized Permian pure play e&p company in a matter of months. We’re operating off a new basis of design and finding that has been incredibly successful.”
2018 Permian oil production is expected to average 3.28 MMBD, up 855 MBD over 2017, while NGLs increase about 220 MBD to around 850 MBD.
Outside the Permian, Bakken oil production in the Williston Basin is expected to increase about 230 MBD in 2019, Eagle Ford oil production by 65 MBD, and the Gulf of Mexico oil production by 225 MBD. Oil and gas liquids production from the STACK, other US resource plays, and conventional oil and liquids production is expected to increase 300MBD. Higher oil prices and lower costs will support growth in other regions.
Canada will produce even less than the small increase expected in 2019. After a 250 MBD increase in production this year to 5.21 MMBD, the EIA now expects a 10 MBD decline in 2019.
Its’ producers are suffering. Inadequate takeaway capacity, both pipeline and rail, and seasonal maintenance at Midwest refineries, magnified a supply glut which drove the Western Canadian Select heavy sour crude discount at Hardisty to a record $52/B below WTI in October. The discount was $10.38/B in 3Q17. WCS closed below $14/B November 14th. Heavy crude production costs approximate $15/B. Margins were in the red. WCS breakeven costs for new projects are roughly $42/B. Reduced cash flow is forcing producers to cancel projects to stay solvent. The winter drilling season could be lost.
Some producers plan to curb output through the year end. In early December, Alberta mandated a cut of 325 MBD from January for 3 months to allow the glut to clear. The cut will be reduced to 95 MBD after that until the end of 2019.
The start of Enbridge’s Line 3 replacement in 4Q19, with increased capacity of 375 MBD into the Midwest, and new pipelines later are expected to ultimately restore the normal WCS discount to WTI.
In the interim, Canadian producers have turned to crude shipment by rail, which hit a record 270 MBD in September. They are expected to reach 300 MBD in December and ramp up to 450 MBD in 2019. In addition, Alberta plans to buy rail cars for 2 unit trains able to move 120 MBD to US refiners from late 2019. Cenovus, Canada’s 3rd largest oil producer, says shipping by rail to the Gulf Coast is just under $20/B.
By 2020, Cenovus expects there will be enough transportation capacity to start emptying Alberta’s record high storage with a WCS discount below $20/B. After the surge in new oil supply from the Permian Basin in 2H19, there may be another sizable surge, this time from Canada, the following year.
A return to growth in Brazil is expected in 2019 after a disappointing 2018, which reflected the impact of steep declines in mature fields and maintenance downtime. Brazil is expected to add 360MBD to world oil supply in 2019 to average 3.06 MMBD. Its production declined 40 MBD in 2018. Petrobras and its partners are starting 7 new production systems this year in Brazil’s prolific offshore subsalt play followed by 2 more in 2019. The IEA anticipates Brazil will be producing 5.2 MMBD by 2040.
Boston Energy Research selects equity investments in the oil and gas sector for major financial institutions.
Paul Kuklinski, founder of independent research firm Boston Energy Research, typically publishes over 30 common stock recommendations annually from a universe comprising the five super major integrated oils, 17 of the largest exploration and production companies, and nine of the leading oil service providers including marine drillers, a total of 31 of the most important energy stocks in all. His comprehensive coverage provides a unique vantage point to observe industry trends not generally available.
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Care and Grooming of a Frac Sand Mine
An acute driver shortage can almost be categorized as infrastructure challenge as well.
By Paul Wiseman
Reminiscent of the 1889 Oklahoma Land Rush, the 2018 Permian Basin sand rush saw excited investors descend on the Basin, opening approximately 19 new sources of this granular gold. Black Mountain Sand opened three of those 19: the Vest Mine, source of what they call “Winkler White,” which opened in January near Kermit. Their El Dorado mine, also near Kermit, opened a few months later, and the Sealy Smith facility, located near Monahans, was the third.
The process of finding usable sand then securing its availability is complex, spreading over multiple years and involving geology, land work, and development.
Hayden Gillespie, chief commercial officer for the two-year-old company, explained how it all works.
To start with, “We’re looking at all the available maps that are out there, whether they’re USGS maps or state surveys—any kind of publically available maps.” Gillespie said.
A worker monitors activity at one of Black Mountain’s mines. Sand is big, and it has not only created jobs but has created new kinds of occupations.
When those investigations reveal an area that might hold sand of a quality and proximity to wells that would make it profitable, Black Mountain goes into an acquisition phase.
“We approach landowners, we try to figure out what we’re looking at (on) ownership maps, we’re looking at potential lease options,” he said. They speak with landowners about test agreements to determine if usable sand is on their land and, if so, in what quantities. Coring rigs in West Texas grab columns about 120 feet deep in order to understand the deposit’s characteristics.
“Is it homogeneous, are we seeing differences in the mesh distribution as we go to different levels, what are we seeing in terms of overburden [or topsoil and organic levels including grasses]?” Gillespie said they’re also looking for the level of the water table.
“The next phase is equally, if not more important, especially in West Texas” said Gillespie, “is understanding the infrastructure.” Access to water, natural gas, electricity, and roads are important to understand before moving ahead. Locating either on an overcrowded county road or an unpaved track, both create access problems that “decreases the value proposition.”
He continued, “We probably drilled 600 core holes across Winkler and Ward counties. We acquired about 29,000 acres in probably 5-6,000 acre contiguous blocks.”
Gillespie compared their analysis procedures to those of an E&P company assessing an area’s rock formations to help them decide whether to lease it for drilling.
“We kind of [assessed] our asset base and said, ‘This particular area that we’re in, we like this spot right here because it generates the deposit we like, the mesh distribution that we like, as well as the ease of access, and the proximity to good infrastructure.’”
Their two flagship facilities are on State Highway 302. “We get access to the Midland Basin real easily, we can access the Delaware Basin, we can go north and south easily.”
Like other frac sand companies, they worked with TXDOT and MOTRAN to assess the road’s ability to handle frac traffic. “We completed a couple of projects with TXDOT in order to improve the ingress and egress from our facility.”
After working with MOTRAN, Black Mountain will also contribute funds to the widening of 302 to four lanes throughout the area accessed by the two mines “so we’ll have a really efficient roadway to access our facility.”
Anticipating challenges well in advance and working through public-private partnerships helps ensure efficient operations as well as safety for all traffic in the area, Gillespie said.
“Access to water, natural gas, electricity, and roads are important…” —Gillespie
Access to electricity is a pretty obvious need for any enterprise, but natural gas is also key for frac sand mines. “We employ natural gas for the purposes of powering our driers, but also, in addition to permanent three-phase power that connects to our facility, we use backup generators which are powered by natural gas.”
“We probably drilled 600 core holes across Winkler and Ward counties.” —Gillespie
An acute driver shortage can almost be categorized as infrastructure challenge as well. Black Mountain is addressing that indirectly, by structuring their loading process so each truck can be filled in 10 minutes. Speeding the process can allow the drivers that are in place to make more trips per day. Increasing efficiency, said Gillespie, is “the next big thing” in the frac sand sector.
For a while now the Permian has played host to more drilling rigs than any other area in the United States. One might wonder if other, less active areas are easier places in which to open and operate—well, anything, including a sand mine.
“A lot of the challenges are the same, when you think about it. The site selection is pretty much the same way, you want to find a really good deposit, you want to find it in good proximity to your customers’ work, and infrastructure in place,” Gillespie said. “Once you develop a really good blueprint, [you can] continue to run those plays in a different Basin.”
“Each site comes with its own set of challenges,” he continued. “Whereas labor force is really tight in the Permian Basin, in the Eagle Ford and in Oklahoma you have really good access to stable, non-transient workforces. That really enables us to give [good] service.” Pipeline constraints don’t exist elsewhere, either.
A big takeaway for Black Mountain, fueling its entry into other basins, is the idea that suitable and plentiful frac sand can be found close enough to almost every basin—which reduces completion costs by as much as a half-million dollars per well. It also alleviates a long list of logistics headaches and shipping delays involved in Northern White or even Brady-area sand.
For example, “In the Eagle Ford, there’s a deposit that is fit-for-purpose that will work in these shale plays. So we see customers creating demand for those products—and to the extent that the demand is there, we’re going to build and produce sand.”
Boom-and-bust cycles that push producers toward automation-enabled efficiencies to cut overhead also drive them toward cutting frac costs with nearby sand. “Born out of the downturn was this idea that… the lowest cost and most efficient option will always be the preferred choice,” Gillespie said. In other words, during a downturn the more distant sand mines suffer first and worst, while localized mines come closer to holding their own.
With current operations in the Permian, in the Eagle Ford, and in Oklahoma, Black Mountain plans to add mines in Colorado’s DJ Basin and the Powder River Basin eastern Wyoming. In November of 2018 there were about 35 rigs in the DJ Basin and the Powder River Basin had approximately 24.
Many experts believe Permian production will continue to rise over the next 10 years, so there should also be a continued sand rush in this area.