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How oil is preparing for a new world order

Dhara Ranasinghe

A new oil order has arrived and it will be marked by greater uncertainty and generally lower oil prices as the oil industry frantically re-prices as costs decline and gains in efficiency are made, strategists say.

As investors continue to weigh up the fallout of a rout in oil prices since June last year, Goldman Sachs has warned that the “level of uncertainty cannot be underestimated as these dynamics spill over into the price of commodities, currencies and consumption baskets around the world, with far-reaching market and economic implications.”

And amid heightened uncertainty, oil prices can swing sharply in either direction as developments this week have shown with a crisis in Yemen triggering a spike in crude.

“Oil has been sideways for about four months, in a $15 range; it hits a bottom, bounces up, hits the top comes back down,” Sean Corrigan, founder of True Sinews Consultancy told CNBC Europe’s “Squawk Box” Friday.

“We’re all waiting for the next break and trying to find the signal that will push us from this range,” he added.

The Goldman Sachs note, published late last week, adds that while it believes “the new equilibrium price for oil is $65 a barrel for WTI [West Texas Intermediate] and $70 a barrel for Brent, the risks are skewed to the downside.”

© Provided by CNBC

Those forecasts would imply gains of at least 21 percent for Brent crude from current levels around $58 and a rise of about 30 percent for WTI, which is trading at around $50.

Still, and more significantly, prices would remain more than 30 percent below peak levels of above $100 a barrel on both oil contracts seen last year before concerns about a supply glut helped drive prices down.

The International Energy Agency said late last year that a slowing Chinese economy and a boom in U.S. shale production had brought about a new era for oil.

Watch out

And oil strategists say there are a number of factors that suggest oil markets will be characterised by uncertainty and volatility in the months ahead.

These include geopolitical risk as seen this week, the prospect of increased supply from Iran if it reaches a nuclear agreement with the West that leads to a lifting of sanctions, and the prospects for alternative fuels as well the rise of shale oil

“We still have quite a lot of variables that could affect the spot price for a long period,” Barclays Oil Analyst Miswin Mahesh told CNBC.

“If you look at Iranian oil production if sanctions are removed, what would they bring into the market, what could Iraq bring into the market?,” he added.

Other analysts point out that speculators betting on where oil prices are headed only fuel that uncertainty.

“If you look at oil ETFs [exchange traded products], there is huge buying interest despite oil prices falling,” Ashok Shah, director of asset management firm London & Capital,” told CNBC.

“There are a lot of non-consumption players out there playing it [oil] for financial gain and that will create more volatility with moves down and corrections up,” Shah said, adding that he thought oil prices could go back down to around $40 and stabilise there.

Complicating matters

Analysts at Goldman Sachs add that the move lower in oil prices since last June has happened at a time when rise in the U.S. dollar’s value, and corresponding fall in commodity currencies such as the Australian dollar and Chilean peso, reduces the cost of producing energy.

“This puts downward pressure on commodity prices and in turn reinforces U.S. growth, a stronger dollar and lower oil prices, suggesting the risks to costs are distinctively skewed to the downside,” the Goldman note said.

Miswin at Barclays said that two developments he was watching closely for the outlook was the solar industry and energy storage.

“There are reports that we will get to grid parity in the next 12-18 months in the solar industry, which has very important implications because that means even without subsides electricity generated by solar power will be one-to-one with conventional energy, he said.

Falling rig counts drive projected near-term oil production decline in 3 key U.S. regions

Jozef Lieskovsky, Richard Yan

Republished March 17, 2015, 10:00 a.m., text was modified to clarify content.

EIA’s most recent Drilling Productivity Report (DPR) indicates a change in the crude oil production growth patterns in three key oil producing regions: the Eagle Ford, Niobrara, and Bakken. The DPR estimates, which were issued on March 9 and cover the months of March and April, include the first projected declines in crude oil production in these regions since publication of the DPR began in October 2013. However, with production gains continuing in other regions, particularly the Permian, overall crude oil production in regions tracked by the DPR rose slightly in March to 5.6 million barrels per day. Total production in the DPR regions in April is expected to be virtually unchanged from its March level.

In any given month, there are new wells and legacy, or continuing, wells. Production from legacy wells declines over time, but recently the rate of decline in some regions has been increasing. This means that, in order for overall production to increase, operators must drill enough new wells to overcome the decline from legacy wells. As fewer wells are drilled, this decline becomes a significant challenge to overcome.

The recent decline in crude oil prices has led operators to reduce the number of rigs in use. DPR results show sharp decreases in rig counts in all regions, starting in January and February of this year. When producers make the decision to lay down some drilling rigs, they generally start by idling the older, least-efficient ones first. The effect on production depends on the productivity of the remaining rigs.

For example, falling crude oil prices during the 2008-09 recession led to decreases in rig counts, but not decreases in production. At that time, lower rig counts were more than offset by increases in the productivity of remaining rigs, as those more productive rigs required fewer days to drill and complete a well, had higher initial production rates, and were more able to drill multiple horizontal wells from a single pad. Because the base level of rig performance is so much higher now than several years ago, it is not clear that productivity gains will offset rig count declines to the same degree as in 2008-09.

The Permian region, whereas late as December 2013 half the operating rigs were vertical rigs, still appears to be experiencing significantly larger productivity improvements than other DPR regions. In general, average production from a vertical well is significantly smaller than that from a horizontal well. As more vertical rigs are brought offline, the ratio of vertical to horizontal rigs in the Permian, which has only fallen below 1:1 in recent months, is coming closer to, but remains above, the vertical-to-horizontal rig ratio in the other DPR regions.

Oil Prices Fall to 6-Year Intraday Low – Sell My Oil Royalties

Investors shrug off OPEC report that U.S. oil output could decline later this year


*Nymex Oil Falls to Intraday Low, Down 3% at $43.50/Barrel



LONDON—U.S. oil prices were close to a six-year low on Monday, with investors largely shrugging off a report by the Organization of the Petroleum Exporting Countries that U.S. oil output could begin to decline later this year.

Markets were instead pulled lower by the prospect of Iranian oil flooding an already oversupplied global market. U.S. and Iranian negotiators are hoping to seal a tentative political agreement on Tehran’s nuclear program before an end-of-March deadline. This could pave the way for increased Iranian oil exports and would be bearish for prices, which are again under pressure after several weeks of relative stability.

April-dated Brent crude on London’s ICE Futures exchange fell 1.3% flirting with $54 a barrel. On the New York Mercantile Exchange, light, sweet crude futures for delivery in April traded down 1.3% to $44.27 a barrel. Last week, Nymex crude fell 9.6% to a six-week low. Brent crude lost 8.5% and has been down for two consecutive weeks.

In its monthly report released on Monday,OPEC said that U.S. oil output may start declining as early as the end of 2015. The group also edged up its global demand estimate for this year by 50,000 barrels a day to 92.3 million barrels a day, projecting that almost half of that demand growth will come from China and the Middle East.

OPEC also said that its February crude oil output was down by 0.14 million barrels a day to 30.02 million barrels a day because of disruptions caused by the continuing turmoil in Libya.

As a sign of upcoming supply cuts in the U.S., the number of oil-drilling rigs has been falling in recent months, although the impact may take several months to show in the actual output. The rig count dropped by 56 to 866 last week, according to Baker Hughes Inc.

However, the rate of the decline has also slowed recently, suggesting that U.S. oil producers are delaying cuts in production capacity. And while U.S. shale-oil producers have slashed spending on drilling, they are poised to increase production quickly by focusing on their best oil fields.

“Naturally, lower rig count would suggest lower crude production; however, with new-well production on the rise, it is enough to taper off reductions in crude production,” Daniel Ang, investment analyst at Phillip Futures wrote in a report.

Talks between the U.S. and Iran are set to resume on Monday, though Western diplomats say serious negotiations over substance would still be needed in the months ahead before any international sanctions on Iran can be lifted.

“What happens with Iran is important because of the direct impact on oil supply,” said David Hufton of brokerage PVM.

Barclays analysts said that the perception that sanctions relief will lead to more oil on the market could pave the way for crude’s next move. “This supports our bearish view, and we see little likelihood of a bullish market reaction to developments in this space,” they wrote in a report.

However, sanctions won’t be removed in one fell swoop, the bank cautioned. “Even in a best-case scenario on sanctions relief, a sea change in Iranian oil exports is unlikely until after June,” Barclays says.

Nymex reformulated gasoline blendstock for April—the benchmark gasoline contract—fell 1.4% to $1.7382 a gallon, while ICE gas oil for April changed hands at $515.50 a metric ton, down $8.25 from Friday’s settlement..

—Benoît Faucon contributed to this article.

Write to Georgi Kantchev at

The Clock is Ticking for Mineral Estate Owners to Ask for Audits

Everyone trying to get their fair share

By Jennifer Hiller

Mineral owners have four years to make sure contracts are followed.

More than a billion barrels of crude oil have flowed from the Eagle Ford Shale, and now many mineral owners want to know whether they’ve gotten their fair share.

More South Texas mineral owners are asking for audits to check their royalty payments, making sure that oil companies are paying correctly and following the requirements of their leases, attorneys say.

Why now?

Oil prices are slumping — causing everyone to scrutinize their statements — and there’s a four-year statute of limitations for making a legal claim for breach of contract.

The Eagle Ford discovery well was drilled in late 2008, but it was a few years before oil production started to surge in the South Texas field. The Eagle Ford now makes around 1.7 million barrels of crude oil and other liquids daily, according to the U.S. Energy Information Administration.

“The clock is ticking,” said Robert Park, an attorney with Uhl, Fitzsimons, Jewett & Burton in San Antonio. “Your statute of limitations for this is four years.”

A basic royalty audit can use an owner’s statements, check stubs and data about the lease that’s publicly available from the Texas Railroad Commission. That could show if there’s a payment problem worth further investigation, Park said, though families that have received more than $500,000 in royalties may want to do a more in-depth audit.

Lease audits look at the terms of the lease — things such as offset obligations or continuous drilling provisions, which require an operator to keep drilling wells to hold a lease. Producing wells usually hold a certain amount of acreage, giving the company the right to drill more wells in the future. But Park said there’s sometimes a difference between the amount of acreage an operator and a mineral owner thinks is being held.

There are also disputes about the surface obligations that may be included in leases where the mineral owner also owns the surface of the property — whether topsoil was replaced correctly after putting in a pipeline, for instance, or whether retention berms were built to keep spills from contaminating the rest of the property.

Some problems pop up again and again: Workers speeding on a ranch, hunting on a property without permission or leaving gates open.

“It’s over and over with people not closing the gates,” said attorney Ezra Johnson, also with Uhl, Fitzsimons, Jewett & Burton.

In one instance, someone was hitting golf balls into a pasture, where grazing cattle ate them.

While oil companies will have the lease on file, as well as a lease summary to refer to for key requirements, Johnson said it’s easy for an operator to lose track of the details of a lease, especially if the original operator sold the lease to another company. This can lead to companies not following the finer details of a lease agreement.

“They get lost in the shuffle of a lot of leases,” Johnson said.

Site visits done as part of an audit have found metering errors, including bypasses that route hydrocarbons around the meter entirely, making it impossible for a mineral owner to know how much oil or gas was produced, Park said. More common problems might be a broken needle on the meter.

The General Land Office does audits of oil and gas production on state lands to make sure the state is being paid properly. State law also gives the GLO the authority to inspect and examine an operator’s books, accounts, reports or other records relating to the payment of royalties.

Ideally, a good mineral lease will allow individual mineral owners similar access to a company’s accounting records.

Mineral owners often assume their royalty payments are correct, but the Texas courts have made clear that the mineral owners have the burden of discovering any problems and taking legal action.

The key case is Shell Oil Co. v. Ross. In that situation, Ralph Lee Ross sued Shell Oil Co. and Shell Western E&P, arguing that the company had for several years underpaid royalty on natural gas under a mineral lease to Ross’ grandmother.

Shell said the error was an accounting mistake. A jury found that the company had fraudulently concealed its underpayments, and the appellate court in Houston upheld the decision in favor of the Ross family.

But the Texas Supreme Court sided with Shell, ruling that Ross had waited too long to discover that the family had been underpaid. The statute of limitations — four years — had long passed by the time Ross sued.

“Readily accessible and publicly available information could have led the Rosses to discover that Shell was underpaying royalty before the limitations period expired,” the Texas Supreme Court ruled. “We hold that evidence conclusively established that Shell’s alleged fraud could have been discovered by the Rosses through the exercise of reasonable diligence.”

But it isn’t all disputes these days. There’s at least one area of the mineral lease where companies and mineral owners are seeing eye to eye right now: No one wants to rush to drill cheap oil.

“The companies asking for more time to drill wells,” Johnson said.

“The operators and the mineral owners feel the same about that one,” Park said.

Twitter: @Jennifer_Hiller

Non Producing Minerals Royalties Louisiana – Inheriting Mineral Estates, Rights

When looking to sell non-producing minerals in Louisiana and the surrounding areas, it is important to know a variety of factors that add or reduce the  value of your property or your interests. Many of these range from the amount of minerals to the state of the minerals themselves, though these are not always the case. Fortunately, BHCH Mineral, a family owned and operated company based out of San Antonio, is here to help. Navigating the world and industry of mineral estates and rights is our specialty.

BHCH Mineral has been purchasing non producing minerals in Louisiana and beyond for over 30 years. We focus mainly on the Haynesville and Tuscaloosa Marine Shale areas, which house the oil and gas reserves of the state. We also work in other states and are in over 15,000 active wells across the United States. Our extensive knowledge and experience in dealing with a variety of estate types, sizes and acquisitions make us the perfect candidate to review what you own.

We will take the time to educate you on your estate or your royalties while creating an accurate estimate. We understand how difficult it can be to sell your interests, whether it is simply because there is plenty of history and sentimental value involved or there is simply too little knowledge available about the estate. Whatever it may be, we will always provide a fair price for what you are offering to sell us. BHCH Mineral will help to explain how exactly we create our estimates as well.

If you are interested in selling your interests or would like to know the value of your non-producing minerals, fill out our online offer form. We will get back to you as soon as we can. You can also call us today at 210.828.6565 extension 2.

Mineral Company Texas

In the United States, Texas considered among one of the richest oil reserves. The area known as the Eagle Ford houses the largest oil and gas development in the world. We at BHCH Minerals, LTD. are a mineral company in Texas. We services areas such as the Texas Panhandle, Permian, Eagle Ford and Barnett.

Because of our interest in Texas, we have taken the time to learn about the area to be able to deliver the most information to our current and future customers. We want you learn more about your mineral estate and your properties, whether or not you decide to ultimately sell. We can also help to dissolve existing mineral estates as well as selling undivided royalties. Our experience as a mineral company in Texas only helps you to become knowledgeable about what your currently have.

The principals of BHCH have been purchasing mineral interests for over 30 years. Our extensive experience in dealing with a variety of acquisitions large and small make us the perfect candidate to inspect and value your holdings. We will never oversell or undersell your properties and we will always provide the most accurate estimates, along with an explanation as to how we have priced your minerals fairly. BHCH and its affiliates have acquired over 12,000 individual properties and are in over 15,00 active wells throughout the United States. You can trust us with whatever you mineral selling needs may be.

If you are interested in selling your minerals or are simply interested in receiving an estimate for what you currently own, call us today at 210.828.6565 extension 2 or visit our website and fill out our form on our Get An Offer page. All of our estimates are completely free! We will guide you through every step of our purchase, from creating an estimate to selling your minerals.

How to Sell Minerals Estate Oil & Gas Royalties in Louisiana

Fair oil & gas royalties in Louisiana may not always be so easy to find, especially for first-time sellers or for customers who are simply interested in learning the value of the resources found on their property. Many times, unfair estimates or inflated market values are given to sellers without any explanation as to why the value is as such. We at BHCH Mineral aim to provide the most accurate estimates to new sellers. We also aim to educate sellers about how we come up with an estimate and how we price your resources.

BHCH Mineral specializes in offering fair oil & gas royalties in Louisiana and the surrounding areas. We take the time to learn about what can be found on your property, as well as what you as a seller are interested in. Whether you simply want to dissolve a mineral estate, want an accurate value analysis of your minerals, or interested in selling the property as a whole, BHCH will look into your interests and provide the information necessary for continuing the selling process.

We have over 30 years of experience in purchasing mineral interests throughout the United States. At every step of our process, we will be quick and straightforward. We want you to not only be satisfied with our services, but to learn more about our process and about oil & gas royalties. Currently, BHCH and its affiliated entities have purchased over 12,000 individual properties and are in over 15,000 active wells throughout the United States.

If you are interested in learning more about BHCH Mineral or would like more information about our services, call us today at (210) 828-6565 ext. 2. To get an offer for your mineral estate or to know the value of your minerals, simply fill out our form today and we will get back to you as soon as possible.

The 10 most mineral and oil-rich states – Texas, California and Louisiana

The U.S. energy industry is booming. As new technologies make oil easier and more affordable to extract, the United States is poised to become the world’s leading oil producer as soon as 2015, according to a 2013 study by the International Energy Agency. At the same time, proven oil reserves — the estimated quantities of oil that can be extracted under existing conditions — have also risen. In 2012, the U.S. had more than 30.5 billion barrels of proven oil reserves, up 15% from the year before.

Ten states accounted for nearly 80% of the U.S. proven oil reserves as of the end of 2012. Texas was the state with the most proven reserves, totaling more than 9.6 billion barrels of oil, or close to a third of all U.S. reserves. Based on the U.S. Energy Information Agency (EIA) data on proved oil reserves, these are the most oil-rich states in the country.

Unsurprisingly, the states with the highest totals of proven reserves are also among the states producing most oil. Of the 10 most oil-rich states, all but one were also among the states with the most production activity as of 2013. Together, these 10 states accounted for more than 2 billion of the 2.7 billion barrels of oil produced last year. Offshore drilling, not attributable to any state, accounted for much of the production not coming from these states.

In addition to being oil-rich, these states also refine the vast majority of oil in the country. Of the nation’s 139 operating refineries, 90 are in the states with the most oil. Together, the nation’s refineries have a refining capacity of nearly 18 million barrels per day. Three of the nation’s most oil-rich states — Texas, California and Louisiana — together have a refining capacity of more than 10 million barrels per day.

Technological advancements in horizontal drilling and hydraulic fracturing, commonly called fracking, have allowed oil companies to access oil shale formations that were previously unreachable. In the Permian Basin, for example, traditional oil wells began to run dry as early as 2000. Using new technologies, the Permian Basin accounted for nearly 25% of total U.S. oil production as of late last year. “Without [horizontal drilling and hydraulic fracturing] much of the ‘unconventional’ production wouldn’t be economic,” explained Don Burch, senior geophysical advisor at Noble Energy.

In addition to new oil fields, companies have increased reserves via extensions to existing and already-producing oil fields. Extensions accounted for nearly half of the increase in U.S. reserves between 2011 and 2012.

As a result of the oil boom in these states, jobs in the mining and logging industries, which include oil and gas extraction, have increased in all these states. Notably, the number of mining and logging industry jobs in North Dakota jumped nearly 60% in 2011 and 47% in 2012.

However, the existence of substantial amounts of oil in a state does not necessarily guarantee work opportunities. California, Alaska and New Mexico had unemployment rates above the national rate in June 2014. Still, an active oil industry can be beneficial to a state’s economy. In Colorado, the nation’s eighth-most oil-rich state, for example, “the oil industry employs 110,000 full time workers [and spends] $30 billion, yielding $1.6 billion in state tax revenue each year,” Burch said.

To identify the most oil-rich states, 24/7 Wall St. reviewed data on proved oil reserves from the EIA. Reserves figures are as of December 31, 2012, the most recent date for which such data are available. We also reviewed EIA data on natural gas and coal reserves, as well as per capita energy consumption figures, for 2012. Per capita consumption is expressed in British thermal units (BTU). Crude oil production figures from the EIA are for 2013. Figures on the number of operating refineries and their capacity are also from the EIA and are current as of January 1, 2014. Unemployment data and jobs figures are from the U.S. Bureau of Labor Statistics.

These are America’s most oil-rich states.

1. Texas

> Proved oil reserves: 9.6 billion barrels
> Natural gas reserves: 93.5 trillion cubic feet (the most)
> Energy consumption per capita: 324.9 million BTUs (21st highest)
> Number of operating refineries: 27 (the most)

Texas accounted for nearly a third of both crude oil and natural gas reserves in the United States in 2012. The state has more than 9.6 billion barrels of proven reserves, a capacity that expanded rapidly in 2011 and 2012 when the state discovered 55 million barrels of reserves from new oil fields and more than 3.6 billion barrels from existing drilling sites. With more than 932 million barrels of oil produced in 2013, and 27 refineries capable of processing nearly 5.2 million barrels per day, Texas leads the nation in virtually all facets of the oil industry. Between the state’s Eagle Ford Shale and Permian Basin, Texas is poised to produce nearly 3.4 million barrels of oil each day in 2014. If Texas were its own country, it would be the sixth largest oil producer in the world.

2. North Dakota

> Proved oil reserves: 3.8 billion barrels
> Natural gas reserves: 4.0 trillion cubic feet (11th most)
> Energy consumption per capita: 254.7 million BTUs (14th lowest)
> Number of operating refineries: 1 (tied, 24th most)

North Dakota has become the poster child of the energy boom in the United States as technological advances made extracting oil from the Bakken Shale profitable. Over the two years ending in 2012, the state added nearly 25 million barrels of proven reserves from new oil fields, and more than 1.6 billion barrels of reserves from current drilling operations. As a result, proven reserves in the state more than doubled. Additionally, between 2003 and 2013, oil production in North Dakota exploded by nearly 1,000%. As a result of the oil boom, jobs in the mining and logging industries — which include oil production — grew at annual rates of nearly 60% in 2011 and nearly 47% in 2012, according to the BLS. When combined with the transportation industry, which supports the mining and logging industry, it was little surprise that North Dakota has consistently boasted the lowest unemployment rate in the country since 2009.

3. Alaska

> Proved oil reserves: 3.3 billion barrels
> Natural gas reserves: 9.7 trillion cubic feet (9th most)
> Energy consumption per capita: 872.7 million BTUs (the highest)
> Number of operating refineries: 6 (4th most)

Oil production in Alaska has slowed over the past two decades. Additionally, proven reserves in the state declined by 13% between 2011 and 2012. Oil production may also have been hindered by newly available oil reserves in the continental United States, which are easier for oil companies to transport to market. Given that the vast majority of funding for Alaska’s state budget comes from oil production, the state could potentially face fiscal trouble in the coming years. In May 2013, Alaska’s Governor Sean Parnell lowered the oil production tax in an attempt to reignite oil drilling interests in the state.

4. California

> Proved oil reserves: 3.0 billion barrels
> Natural gas reserves: 2.1 trillion cubic feet (8th least)
> Energy consumption per capita: 201.1 million BTUs (3rd lowest)
> Number of operating refineries: 17 (3rd most)

California’s 2.9 billion barrels of proven oil reserves made it the fourth most oil-rich state in the nation in 2012. In terms of production, California ranked third, with nearly 200 million barrels produced in 2013. Additionally, California is also a top oil-refining state, in part because of the stringent regulations California has in place on the amount of oxygen allowed in gasoline — which makes imports from other states prohibitive. Additionally, California’s ongoing water shortage may make it difficult for oil producers to expand their activities in the state. Despite its high oil production, California’s per capita energy consumption ranked third lowest in the country in 2012.

5. New Mexico

> Proved oil reserves: 965 million barrels
> Natural gas reserves: 14.6 trillion cubic feet (7th most)
> Energy consumption per capita: 256.2 million BTUs (15th lowest)
> Number of operating refineries: 2 (tied, 17th most)

New Mexico has benefited from new extraction technologies. Despite wells running dry in the early 2000s in the Permian Basin, which occupies 300 miles in New Mexico and Texas, fracking and other extraction methods allowed access to previously inaccessible oil reserves in 2010. Quickly, crude oil production in New Mexico grew to historical levels, increasing by more than 50% from 2010 to 2012. A new oil field and 170 extensions in 2012 also buoyed oil production. New Mexico also has the seventh largest natural gas proven reserves and the 10th largest coal reserves in the country.

Scoop, Stack And SoHot – A Guide To Oklahoma’s Oil-Play Acronyms

The plays stretch from northwest of Oklahoma City to near the Texas border.

Unit Petroleum Corp., the E&P unit of Unit Corp., stepped up in May with an acronym of its own for an Oklahoma oil play—SoHot, representing “southern Oklahoma Hoxbar oil trend.” The company plans 13 wells this year in the play, in Grady County southwest of Oklahoma City.

“The SoHot has six stacked sands,” reports securities analyst Marc Bianchi with Cowen & Co. “Thus far, Unit has drilled and completed horizontals in two of the zones, identifying an oily zone—Marchand—and a gassy zone—Medrano.”

The Hoxbar is a roughly 2,000-foot-thick, Pennsylvanian-age sequence of sand and shale intervals, according to Unit, which estimates it to contain four to six sand intervals that may be commercial. The oily Marchand sandstone is at about 11,000 feet; the gassy Medrano sandstone, 9,800 feet.

With a 4,300-foot lateral, the Marchand wells cost some $7 million and may produce 300,000 to 500,000 barrels of oil equivalent (BOE)—85% to 90% oil—Unit reports. With a similar lateral, the Medrano wells cost some $4.2 million and may produce 3.0- to 4.5 billion cubic feet of gas equivalent, 30% liquids.

In the southwestern Grady County area, Unit has 12,810 net acres across 50,560 gross. With an $82-million budget for it this year—increased some 50% in May—it expects to have three rigs drilling it in the second half.

Bianchi reports that the position may offer 175 to 200 SoHot well locations with most of these targeting the gassy Medrano. Unit’s funding of the SoHot program and an uptick in Granite Wash drilling in western Oklahoma will be from a reduction in Mississippian Lime drilling “where results have been inconsistent,” he reports.


Also targeting Grady County, Continental Resources Inc. revealed its Scoop play in 2012, creating the acronym for it from “south-central Oklahoma oil province.” The play, south of Oklahoma City and reaching toward the Texas border, is concentrated in the oil window of the Devonian-age Woodford shale, where the formation is up to 400 feet thick at about 15,000 feet. It is focused largely in Grady, McClain, Garvin, Stephens and Carter counties, and Continental counts some 450 wells now by it and other operators, delineating the play. Continental has some 425,000 net acres.


Following on Continental’s Scoop, Newfield Exploration Co. announced its Stack play last fall, naming it for “Sooner Trend, Anadarko (Basin), Canadian (and) Kingfisher (counties).” The play, which is northwest of Oklahoma City, targets the Woodford as well as Mississippian-age shales.

The Sooner Trend Field has produced nearly 500 million barrels of oil since its discovery in 1945. Newfield pioneered the dry-gas Woodford-shale play in 2003 in the western Arkoma Basin, east of its current, liquids-rich Woodford play in the Anadarko Basin. It has more than 170,000 net acres prospective for Woodford in its Stack play and more than 150,000 net prospective for the overlying Meramec. It also has some 75,000 net acres in the Scoop play.


Midstream operator Oneok Partners LP reported this week that it is building a 200-million-cubic-foot-per-day gas-processing plant in the midst of the Scoop play to monetize associated gas from the oil production.

Oklahoma’s monthly oil output has grown from 5.7 million barrels in April 2010 to 10.5 million this past April, according to Energy Information Administration data. The rate was last exceeded in January 1989. The state’s production reached 14.5 million barrels in January 1986, according to EIA data beginning in January 1981.

Unit Corp. has employed another acronym in its operations: Rig-operator subsidiary Unit Drilling Co.’s new-build rig has been dubbed Boss for “box on (box) self stacking.” Its first Boss is at work and three more, which are each also contracted, are being constructed.

Well Completion 101: Unlocking Downhole Treasure Part 1 Casing

Once upon a time the success or lack of success of an oil and gas well had to do with the comparative fortune of finding the right sort of producing field. (Here’s a great article on East Texas wildcatter Columbus Earl Joiner that gives a solid flavor of that experience.)

But once you had struck oil, how would you deliver that oil to market?

Well Completion is the process of making a drilled well ready for production.

In the days of Mr. Joiner, well completion consisted of running a steel pipe down the hole, casing that pipe in cement (this cementing was relatively new technology in the 1920s – at the time more for preventing ground water from contaminating the oil than vice versa), and then hooking the appropriate valves and pump fixtures at the surface for delivery into pipeline or truck delivery to refineries.

Fast forward to today and well completion is the special sauce. As our tight oil and gas plays explore the source rock from the gushers of yore and provide us with more economic and energy stability, the art and science of well completion is what enables this new era of E&P.

Well completion is generally broken down into three phases:

Casing – where the piping is run and the cement casing is pumped in.
Perforation – where holes are blasted through the casing at precise locations for stimulation and production flow. Often done in conjunction with tubing, packing, and setting up the Christmas tree.
Stimulation – Hydraulic Fracturing, Acidizing. Preparing the rock formation for optimal flow.
For Part 1 of this series I will focus on Casing.

The pressure builds
When discussing downhole operations it is very important to understand how very complex the calculations are to ensure a proper balance between your drilling mud weight (and cement and other drilling fluids) and the shifting downhole environment. With increasing depth comes increasing pressure and temperature; different geological formations have different pore pressures; and faulting can shift the formations you are working through unexpectedly. I am not an engineer and this post is just an overview, but if you have a flair for math and physics, Petrowiki gets into the necessary calculations.

Casing the joint
After you’ve drilled your well, done any wireline testing and coring, and you feel there appears to be a sufficient quantity of oil, you are done with the open hole portion of your operation. (Dry holes are plugged and abandoned (P&A) with cement plugs).

Broadly there are three types of casing – surface, intermediate and production casing.

Surface casing runs from the surface down to some distance below the deepest known aquifer. Primarily surface casing is designed to protect the hole from contaminates and protect surface water and other formations from erosion and contamination from the well. The way surface casing is structured also provides stability for the downhole drilling operation and prevents collapse of loose soil near the operation.

Intermediate casing, also known as protection pipe, may then be run at various intervals to balance the effects of pore pressure versus fracture pressures over the open column of increasing mud weights.

Production casing protects the production zone, and isolates the producing intervals.

Nesting, nesting, 1, 2, 3…
One of the key ideas about how drilling and casing are set up is the idea of nesting. Near the surface the hole and casing is comparatively large – sometimes up to 24” in diameter. As the hole progresses downward the size of the hole steps down periodically such that the next section of well will be drilled by a bit that fits within the previous section. Like Russian dolls or a telescope. This animation illustrates the nesting concept well.

Time for your annulus review
As you reach the desired length of your new nested section, you have to case that section before moving on. There are different proprietary methods for flowing the cement in (Erle Halliburton made his original fortune from a technique for cementing that he patented in 1920), but in most cases the stages involved are:

  1. Run continuous steel (or other material appropriate to the downhole environmental conditions) piping the length of the new section, with a float valve attached to the bottom of the section. (This will likely be anchored to the previous section)
  2. Start pumping cement in the piping, down through the valve, and up through the annulus until the appropriate volume of cement has been pumped in.
  3. Place a wiper plug into the piping and continue to pump drilling mud behind the wiper until the wiper plug has reached the original float valve.
  4. Allow the cement to set up completely (in most cases this takes about 90 minutes).
  5. Send your next stage drill bit through the piping and drill out through the float valve and concrete plug and on into the next section.

Materials and operations
Because of the segmented nature of the casing operation, it occurs mostly in sequence with the drilling operation, and hence is largely done with the drilling rig in place. (Final production casing may be done with a workover rig.)

As previously indicated the piping is usually steel, although in highly caustic situations different alloys such as nickel may be substituted. From an economic standpoint, steel is preferred. For the vertical surface and intermediate sections these would be fixed pieces of pipe joined together. As the situation downhole becomes more directional, operators may use rolls of “coiled tubing” (up to 3.5”!) that are designed to make the directional changes required.

The cement slurry is mixed at the surface and again is doctored with additives to adjust density and curing time and weight based on the downhole environmental conditions. Portland cement is the most common base material and other components like sand and iron oxide may be added to that as well.

Interested and need more info?

BHCH Mineral, LTD

BHCH Mineral, LTD    |    5111 Broadway, San Antonio, TX 78209
Phone: 210.828.6565 Ext. 2    |    Fax: 210.828.1688