Economic Optimism For Ohio And Utica Shale Oil And Gas

It sure looks to me like Ohio and the rest of the "Rust Belt" could use some positive economic news.  Let's hope the development of the Utica Shale (and the other shale formations) for oil and gas works out.  The area has attracted a lot of industry interest, and usually these companies do not invest the amounts of money they have been putting into leasing up acreage in Ohio without being pretty certain of success.  This is an emerging play to pay close attention to.
Peter

BP CEO: In Early Stages Of Evaluating Ohio's Shale Potential

by Dow Jones Newswires

Source: http://www.rigzone.com/news/article.asp?a_id=119393

Angel Gonzalez

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Friday, July 13, 2012

 

BP PLC is in the early stages of evaluating Ohio's energy potential but believes the state--which is home to the emerging Utica shale--could be a significant contributor to the energy industry, Chief Executive Bob Dudley said Friday. In a speech in Cleveland, Mr. Dudley said BP technicians are already on the ground "advancing a plan to safely appraise the resources" the company is prospecting in leases acquired about four months ago in the Utica and Point Pleasant shales, according to a transcript of the speech. The executive cited estimates by the Ohio Department of Natural Resources that put the state's recoverable shale potential at up to 5.5 billion barrels of oil and 15.7 trillion cubic feet of natural gas. "In the coming months, we expect to acquire seismic surveys, prepare a development plan and survey land for initial wells to be drilled next year," Mr. Dudley said. BP is one of several companies seeking to tap the unconventional oil resources that have revolutionized energy production in the U.S . Production of natural gas in the neighboring Marcellus shale, which underlies several northeastern states, has revitalized formerly depressed areas by providing cheap energy for steel manufacturing and low-cost feedstock for chemical products. The oil industry hopes that the shales underlying Ohio could have large deposits of profitable crude oil. Copyright (c) 2012 Dow Jones & Company, Inc

Optimistic Future For Oil And Gas Drilling And Production In Ohio

Let's keep a close eye on what is going on in Ohio as this development takes place.  I must caution however, beware of the hype.  Salespeople have been known to exaggerate the value of products they are selling.
Peter

            

New map showing revised gas-oil drilling prospects in Ohio creates stir

By Bob Downing
Beacon Journal staff writer
Published: April 24, 2012 - 11:16 PM | Updated: April 25, 2012 - 11:47 AM

http://www.ohio.com/business/new-map-showing-revised-gas-oil-drilling-prospects-in-ohio-creates-stir-1.302678
                     

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New map showing revised gas-oil drilling prospects in Ohio creates stirApril 25,2012 03:47 PM GMTBob DowningBeacon Journal Publishing Co. Copyright � 2012 Beacon Journal Publishing Co. Inc and Black Press. All Rights Reserved. Any copying, redistribution or retransmission of any of the contents of this service without the express written consent of the Akron Beacon Journal is expressly prohibited.

A relatively simple multi-colored map is creating a buzz in eastern Ohio.
Some counties’ residents are ecstatic at the possibility they might be sitting atop lucrative deposits of natural gas/oil products. Others are dismayed to learn smaller volumes of gas and oil might lie deep under their feet than previously estimated.

At the center of what’s happening is a newly released map from the Ohio Department of Natural Resources’ Division of Geological Survey. It shows excellent drilling potential under much of Stark County. Large tracts of Tuscarawas, Coshocton and Trumbull counties also rate excellent. So, too, does eastern Portage County.
Larry Wickstrom, one of four men involved in developing the map, says he is a little flabbergasted by all the attention it is getting.

The map is “just the addition of new information ... and fine-tuning what we have,” he said. It is merely the state’s best guess as to what might be found thousands of feet underground.
Areas outside the main development area could still be productive, he advised, and the map probably will change as state geologists get even more information.

The map, relying on new data, shows a slightly different footprint in eastern Ohio for Utica shale, identifying a core area for drilling that covers 10.8 million acres from Ashtabula County south into Guernsey County.

Much of the drilling in Ohio has been located in Carroll, Harrison, Columbiana and Jefferson counties. Those four counties generally rate good to very good, according to the new data.
Summit, Medina, Wayne and Portage counties are all in the good area. Most of Cuyahoga, Lake and Lorain counties are now excluded.

The map was unveiled to little fanfare in March at a statewide meeting of the Ohio Oil and Gas Association and has gotten increasing attention as word of its existence has spread. It is based largely on the level of hydrocarbons found in Utica shale cores the state owns.

Over the years, more than 40,000 wells have been drilled through the Utica shale to deeper formations. The state has stored those core samples at Alum Creek State Park near Delaware.
Occasionally, researchers would sample the cores. Then about three years ago, the samples started generating increased interest from drilling companies.

Companies took core samples to have them analyzed in their labs. Because they paid for the studies, the companies were allowed to keep their research private for a year before giving the data to the state.

As the information began trickling in, state geologists took the new data and began revising its maps.
To date, energy companies have drilled 60 horizontal wells into the Utica shale in Ohio, and a total of 194 permits have received state approval. That total includes 10 permits in Stark, six in Portage and one in Medina counties.

State officials have predicted that more than 2,250 wells could be drilled in Ohio by the end of 2015.
One big question that remains unanswered is whether there is enough pressure in the western part of the Utica shale formation, where it is thinner, to send oil up well shafts, Wickstrom said.
Most of the drilling companies have not begun to prospect the potentially oil-rich area that generally lies west of Interstate 77.

The exception is Oklahoma-based Devon Energy Corp., which has applied for state permits for wells in Medina, Ashland and Knox counties. The company has said it is more interested in Ohio’s oil than its natural gas.

Chesapeake Energy Corp. is the No. 1 player in Ohio and is attracted by the so-called wet gases: ethane, butane and propane that are found in Utica shale. That makes Ohio financially attractive at a time when natural gas prices remain very low.

Records show landowners can get signing bonuses of up to $5,800 an acre plus royalties as high as 21 percent on what’s produced by wells. The average leasing bonus in Ohio is about $2,500 an acre.

Bob Downing can be reached at 330-996-3745 or bdowning@thebeaconjournal.com.

Another New Shale Play: Newfoundland, Canada

It looks like a new oil exploration and development play might be taking shape in Canada's northeastern Province of Newfoundland.  The target appears to be the stratigraphic equivalent of the Utica Shale of the Ohio, and New York areas in the United States.  In the area of interest off the west coast of Newfoundland around Port au Port Bay, they call this the "Green Point Shale".

source: http://seekingalpha.com/article/412511-newfound-billions-of-barrels-of-shale-oil-in-newfoundland?source=email_macro_view&ifp=0



Source: Shoal Point Energy website.
Here is a link to a map showing all of the oil and gas activity in eastern Canada.

Oil exploration and production is well established in the offshore basins of eastern Newfoundland with fields such as Hibernia, Terra Nova, and White Rose producing around 300,00 barrels of light crude per day.  (One wonders why exploration and production off Canada's east coast has been allowed where geologically similar areas off the U.S. east coast are off limits.)  Newfoundland is also "friendly" to the oil and gas business, both environmentally and economically.  There is even a refinery in Newfoundland , a good infrastructure network, and a trained workforce in place, presumably eager to expand and grow.  Again this is a refreshing contrast to the U.S.

The Green Point Shale in Newfoundland apparently compares well with the south Texas Eagle Ford Shale that is attracting so much attention.  These factors include total organic content (TOC) of the shales and the thermal maturity of the shales, that is their ability to contain and produce both oil and gas.  One major difference is the Green Point Shale is far thicker in this area than the Eagle Ford Shale is in Texas.

Apparently the Green Point Shale is much thicker than the Eagle Ford Shale, (and many other shales) because it has been through at least one episode of comressional tectonics, or mountain-building.  This has taken the layers of shale, and compressed them, pushing them together like a deck of cards on a table would be pushed together to overlap into a single large deck of cards.  This is a positive aspect to this play.  The negative to this "mountain building" is the layers of rock are much more structurally complex than the shales in for example, the Eagle Ford Shale, Barnett Shale, Haynesville Shale, and the Bakken Formation.  This makes for more difficult drilling and development.  On the other hand, these shales probably compare more favorably with the successfully developing Marcellus Shale in the Pennsylvania area of the eastern U.S.

The exploration of the Green Point Shale is in its preliminary stages but there are some very positive initial results in the area.  However the claims of "Billions" of barrels of oil seem premature and a bit sensational to me, still this area is very much worth watching.

This activity is discussed in more detail here:

Peter

US and Canadian Shale Gas Plays Examined

Study analyzes nine US, Canada shale gas plays

A recent study has estimated that nine US and Canada shale-gas plays may produce as much as 24 bcfd by 2018. (source)

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The Oct. 6, 2008, Tristone Capital Inc. study evaluated the gas resources in the Bamett (Fort Worth basin), Deep Bossier, Haynesville, Fayetteville, Woodford, and Marcellus shales in the US and the Montney, Hom River (Muskwa), and Utica shales in Canada (Fig. 1).

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The study expects companies ultimately to recover from these resources 261 tcf of gas, based on various risk factors applied and a long-term average gas price of $8.50/MMbtu. Without the risk factors, Tristone Capital says these shales have a 743-tcf recovery potential (Fig. 2).

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Fig. 3 shows the study’s estimated production from these plays, and Fig. 4 shows its US well completion forecast.

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Several emerging shale plays with limited well control also may contribute additional gas to future production, according to the study. These include the Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.

Shale play comparison

The study says that shale-gas plays owe their success to a balance of various parameters along with constantly evolving drilling and completion techniques and infrastructure. “It is commonly said that no two shale gas plays are exactly alike,” the study says.

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Table 1 summarizes shale-gas play attributes, and Fig. 5 compares the arithmetic average of the attributes. The study notes that the most productive core portions of plays may deviate from the averages.

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Multistage hydraulic fracturing along a horizontal lateral and improvements in stimulation are main factors influencing shale-gas development economics. The study says these factors have improved economics by more than three times from that of vertical well developments by improving both ultimate recovery and initial production rates.

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Table 2 compares typical lateral lengths and frac treatments for the nine plays.

The three types of frac fluid noted are slick water, CO₂-polymer, and gelled cross-linked oil-based fluid.

Slick-water fracs use a nongelled fracturing fluid with low proppant concentrations and a friction-reducing chemical additive that allows pumping the water into the reservoir faster. The fluid often is a brine or potassium chloride (KCl) water to inhibit swelling of clays. The study notes that this fluid is less expensive than hydrocarbon-based fluid and works best in low-permeability reservoirs

Companies pioneered slick-water fracs first in the Fort Worth basin’s Barnett shale.

The CO₂-polymer frac fluid contains emulsified CO₂ in a methanol-water mixture of 5% water and 20% methanol. The study says the mixture appears to minimize reservoir damage and maximize fluid recovery from multiple diversions in the well. Including CO₂ also reduces by 25% the fluid required and provides extra energy, as the gas expands, during frac fluid flow-back greatly to shorten cleanup time, the study says.

The Montney formation in British Columbia is where companies use this fluid. The study notes that stimulating a horizontal well in the Montney typically involves perforating, isolating, and fracturing 6-11 zones at a cost of about $100,000- 120,000/frac interval. It is common to spend more than $1 million for fracturing these wells, the study says. The study describes these jobs as needing 8-10 pump trucks or about 18,000-22,500 hp and taking more than 1 week to complete.

The study notes that companies initially used gelled cross-linked oil-based fluids as the “fluid of choice” for hydraulic fracturing because of its compatibility with most formations and its cold weather attributes. In several basins, slickwater fracs have replaced oil-based fracs because the slick water uses less water and costs less, the study says.

To prevent swelling and permeability loss in the shales, companies typically continue to use oil-based frac fluids in formations that contain extensive water-sensitive clays. The study notes that these fluids are used in the Fayetteville, Haynesville, and Woodford shales.

Fort Worth basin Barnett

Development activity continues to evolve with part of the current activity in urban sites such as Fort Worth and the Dallas-Fort Worth airports.

The study notes that as of Aug. 18, 2008, the Barnett had 8,416 gas wells drilled in 19 counties. Production had increased to 3.8 bcfd in first-quarter 2008 from 219 MMcfd in 2000. The study expects the shale to produce 6-7 bcfd in the next 5 years.

Some of the newer techniques in the play noted in the study are:

• Longer horizontal laterals, up to 3,500 ft, often drilled from pads with multiple wells, especially in the urban areas.
• Testing of tighter well density with laterals, spaced 250-ft apart (25-30) compared with 500 ft between laterals (50-acre spacing).
• Simultaneous fracing of wells to increase recovery.

Deep Bossier

Wells in Deep Bossier of East Texas reach a 15,000-20,000 ft depth, have pressures of about 15,000 psi, and have tested at 65 MMcfd. The study notes that these wells are expensive, costing $10-20/million for a vertical well.

Currently the play has six main fields in four counties: Robertson, Leon, Freestone, and Limestone.

Fayetteville

The Fayetteville shale in Arkansas is the shallower and thinner equivalent of the Barnett shale. The core of the play is in five counties in central Arkansas: Cleburne, Van Buren, Conway, Faulkner, and White.

The study says as of May 31, 2008, the play had 877 producing wells, with production in July of 740 MMcfd compared to only 90 MMcfd in December 2006. The study expects the play to produce 3.15 bcfd by 2018.

Haynesville

The Haynesville shale is in northwestern Louisiana and East Texas. Wells in the play initially have produced 5-20 MMcfd, the study said. The study expects wells to have ultimate gas recovers of 4-8 bcf.

Currently, companies have drilled about 20-25 horizontal wells in the play, and the study expects about 60-80 rigs could be active in the play by yearend 2008, with most of the drilling in Caddo and DeSoto Parishes in Louisiana.

Woodford

The Devonian-aged Woodford shale lies at 6,000-14,000 ft depths in the Arkoma basin of southeast Oklahoma. The study notes that the $6 million well cost in the Woodford is more than the $2-3/million/well cost in the Fayetteville and Barnett shales.

The study estimates that an 80-acre well in the Woodford will recover about 4 bcf of gas.

Marcellus

The Marcellus shale in the Appalachia basin extends over several states, although most wells drilled to date have been in Pennsylvania, the study notes.

It says Marcellus production has been minimal to date because of the need to expand the existing infrastructure to accommodate the high-pressure gas that the gas transportation system in Appalachia cannot at this time handle.

Most companies have so far drilled mostly vertical wells to delineate the play, but the study expects horizontal wells to be the primary means for developing the formation.

Montney

The Montney shale lies in the east-central part of British Columbia. The study notes that continued drilling should increase production to 1 bcfd by yearend 2009 from the current 600 MMscfd in early 2008.

Operators typical include five to eight fracs/well, and the study expects estimated ultimate gas recovery to increase to 7 bcf/well from the current 5 bcf/well as technology innovation continues.

Horn River basin

The Horn River basin in Northeastern British Columbia extends into the Northwest Territories. The Devonian Muskwa shale is the main play although the basin also has other shales with large original gas in place such as the Fort Simpson, the study says.

Initial well production rates have ranged from 2 to 8.8 MMcfd with wells with more fracs stages producing better, the study notes. The study says estimated ultimate gas recovery ranges from 4 to 6 bcf/section.

Utica

The Utica and the overlying Lorraine shales are relatively new plays in Quebec with only a few wells testing the formations to date. The study estimates that recoverable gas could be as much as 40 tcf (150 bcf/section).

An initial vertical well tested at 1 MMcfd; rates should be higher for horizontal wells with multiple fracs, according to the study.

Emerging plays

Three emerging shale plays listed by the study are Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.

The study says the Pearsall is as deep as 3,500 m in places, has a 200-300 m thickness, and contains about 30-175 bcf/section of original gas in place. It notes reports that say initial horizontal wells flowed at 0.8-3.8 MMcfd.

The Niobrara shales outcrop in Kansas and Nebraska, but are at more than 2,500 m depths in western Colorado. The study notes that in the eastern shallower portion of the play, the shales are underpressured and wells have low initial rates, while in the deeper overpressure portion, wells may produced at 1 MMcfd and recover 100-150 bcf of gas/section.

The Barnett in the Delaware basin is twice a deep as the Barnett in the Fort Worth basin and therefore holds much more gas per section. One estimate is that the Delaware Barnett has 500 bcf/section compared with 150 bcf/section in the Fort Worth basin. The study notes that developing Delaware Barnett gas will be more complicated and costly.