2011 Drilling Highlights - Oklahoma Geological Survey - University ...

THE JOURNAL OF THE OKLAHOMA CITY GEOLOGICAL SOCIETY 

VOLUME 62 ~ MARCH | APRIL 2012 ~ NUMBER 5 

Oklahoma 2011 

Drilling Highlights, 

The Geology and Deep 

Structure of the Oklahoma 

Ouachita Mountains – 

The SOPC 1-22 

Weyerhaeuser Well, 

And much more.

Volume 62 | Number 5 

The Journal of the Oklahoma City Geological Society 

Shale Shaker Staff 

EDITOR: 

Michael Root, CEO, TerraQuest Corporation 

[email protected]; [email protected] 

405-359-0773 

ASSOCIATE EDITOR: 

Neil H. Suneson, Oklahoma Geological Survey 

[email protected] 

GEOLOGISTS WIVES ASSOCIATION: 

Stacy J. Harris, Geologist Wives 

PRODUCTION & DESIGN: 

Theresa Andrews, Art Director, 

Visual Concepts & Design, Inc. 


405-514-5317 

EDITORIAL BOARD: 

M. Charles Gilbert, Geologist, 

ConocoPhillips School of Geology and Geophysics, OU 


Michael W. Smith, 

Geologist, Weston Resources, Inc. 


Raymond W. Suhm, 

Independent Geologist, Consultant 


Kris Wells, 

Geologist, Mustang Fuel Corporation 


OCGS Executive Committee 

PRESIDENT: 

Greg Flournoy, Schlumberger Oilfield Services 

VICE PRESIDENT: 

Mark Goss, RKI Exploration & Production 

SECRETARY: 

Jami Poor, MAP 

PAST PRESIDENT: 

Suzanne Rogers, Sandstone Energy Acquisitions Corporation, 

Chair of Energy Libraries Online 

TREASURER: 

Hank Trattner, Trattner & Associates 

LIBRARY DIRECTOR: 

Steve Harris, Okland Oil Company 

COUNCILOR: 

Jim Franks, Independent Consulting Geologist 

WEBMASTER: 

John McLeod, Chesapeake Energy Corporation 

SHALE SHAKER EDITOR: 

Michael Root, CEO, TerraQuest Corporation 

SOCIAL CHAIRMAN: 

Greg McMahan, SandRidge Energy, Inc. 

AAPG MID-CONTINENT REPRESENTATIVE: 

H.W. (Dub) Peace 

ENERGY LIBRARIES ONLINE CHAIRMAN: 

Suzanne Rogers, Sandstone Energy Acquisitions Corporation 

OCGS Offices and Geological Library: 

120 North Robinson, Suite 900 Center, 

Oklahoma City, OK 73102 

Phone: (405) 236-8086 | Fax: (405) 236-8085 

Website: www.ocgs.org 

Michelle Hone, 

Accounting Manager/Administrative Assistant 

Email: [email protected] 

Pam Yeakley, Library Manager, OCGS 

Email: [email protected] 

March ~ April 2012 | Page 337

Table of Contents 

The Journal of the Oklahoma City Geological Society 

Shale Shaker Features 

342 Oklahoma Is Set To Lead The Nation; Michael 

Root, Editor, CEO, TerraQuest Corporation, 

Edmond, OK 

360 Oklahoma Well Status; Randy Peterson, IHS 

395 State of the Industry; Michael Root, Editor, CEO, 

TerraQuest Corporation, Edmond, OK 

Oil and Gas Exploration 

362 The Geology and Deep Structure of the 

Oklahoma Ouachita Mountains - The SOPC 1-22 

Weyerhaeuser Well; Michael D. Allison, North 

Texas Sample Log Service; William H. Willis 

II, Manager, Southern Minerals, Weyerhaeuser 

Company; Dr. Neil Suneson, Oklahoma 

Geological Survey 

302 Oklahoma 2011 Drilling Highlights; Dan T. Boyd, 

Oklahoma Geological Survey 

About the Cover 

Page 338 | March ~ April 2012 

Professional Organizations 

344 Oklahoma Geological Foundation Report; Thomas 

C. Cronin, OGF Chairman, CEO, K. Steward 

Exploration LLC 

345 OGGS 2011 Christmas Party; Greg McMahan, 

Social Chairman SandRidge Energy, Inc. 

352 The 2012 5th Annual Real Deal Mid-Continent 

Prospect Expo 

354 Geologist Wives Association; Stacy J. Harris, 

Reporter 

377 Oklahoma City Geological Society Library 

Geological Treasure Chest 

Oklahoma Universities 

Michael Root creates the covers of the Shale Shaker. The cover for this Issue utilizes an 

image supplied by Michelle Dodd, Coordinator of Photography for Chesapeake Energy 

Corporation and is one of many contained within Chesapeake’s Visual Resource Center. 

The cover ties nicely with this Issue’s technical subject matter: “Oklahoma 2011 

Drilling Highlights,” by Dan T. Boyd, of the Oklahoma Geological Survey; and “The 

Geology and Deep Structure of the Oklahoma Ouachita Mountains – The SOPC 1-22 

Weyerhaeuser Well,” by Michael D. Allison, North Texas Sample Log Service, William 

H. Willis II, Manager - Southern Minerals, Weyerhaeuser Company, and Neil H. 

Suneson, of the Oklahoma Geological Survey. 

357 Shell Colloquium Series Schedule, Fall 2011; 

Lisa Vassmer, Special Events and Donor 

Relations, ConocoPhillips School of Geology and 

Geophysics, The University of Oklahoma


By: Dan T. Boyd, Oklahoma Geological Survey, (405) 325-8898 | [email protected] 

Oklahoma 2011 

Drilling Highlights 

This article is a summary of Oklahoma 

drilling activity that became public in 

2011. Any activity or key wells that were 

unavailable before January 1, 2012 will 

appear in next year’s summary. Except 

where noted, all data were supplied online 

by Petroleum Information/Dwights 

LLC dba IHS Energy Group, all rights 

reserved. A lax State attitude towards 

completion and production reporting has 

created extraordinarily long lag times in 

receiving these data, making analyses of 

recent activity difficult. Without the Energy 

Information Administration (E.I.A.) 

and especially the information provided 

by the IHS Energy a report of this kind 

would not be possible. Editing of this article 

was performed by Neil Suneson and 

cartography by Russell Standridge, both 

from the Oklahoma Geological Survey. 

General Activity 

The number of working drilling rigs is a 


fundamental barometer of oil and gas activity 

and Baker Hughes Company tracks 

monthly rotary drilling rig counts for regions 

all over the world. After a weekly 

peak of 219 in September, 2008 Oklahoma’s 

rig count reached a low of 69 

working rigs in September, 2009 (Boyd, 

2010). Since that time numbers have been 

steadily climbing, with the last week of 

2011 reaching 195 working rigs. This has 

brought the annual average for the year up 

to 180 and marks the second year of major 

increases in drilling activity (Figure 1). 

Oklahoma’s rig count is now on a par with 

levels seen prior to the collapse of oil and 

gas prices that occurred at the end of 2008. 

In past years as many as 3/4s of all wells 

drilled in Oklahoma targeted gas, which 

has made its price the most important factor 

controlling drilling. This is no longer 

the case. Although the price for both gas 

and oil fell at the end of 2008, oil has 

largely recovered and gas has not (Figure 

2). Using the standard 6 MCF per barrel 

conversion, on a barrel of oil equivalency 

(BOE), in 2003 gas and oil prices were 

equal. While 2011 oil prices have risen 

to near their 2008 peak, gas is now selling 

for less than it did in 2003. In fact, on 

a BOE basis oil is now over three times 

more valuable than gas, and this will likely 

continue. Oil remains between $90 and 

$100 per barrel, but gas has again missed 

the usual winter price increase that occurs 

during the peak-heating season and has 

declined steadily since June (Figure 3). 

The latest estimate from the Oklahoma 

Corporation Commission (OCC) places 

the average 2011 wellhead natural gas 

price in Oklahoma at approximately $4.67 

per MCF (Soltani, 2012) (Figure 2). This is 

an optimistic forecast as it is based mostly 

on prices in the first half of the year. Although 

the sharp fall that occurred in the 

second half of the year will be eased by 

hedged contracts and higher Btu gas, the

Figure 1. Oklahoma annual rotary rig count from 2002 to 2011. Data from Baker Hughes (2012). 

Figure 2. Oklahoma annual average oil and gas price on a barrel of oil equivalency (BOE) from 2003 through 2011. Data from Soltani 

(2012). 



Oklahoma 2011 Drilling Highlights, cont. 

Figure 3. Henry Hub natural gas spot price from January 3, 2011 through January 17, 2012. Adapted from Williams, (2012) 

average for 2011 will undoubtedly show a 

significant fall from 2010. The continued 

decline of Henry Hub Spot prices below 

$3/MCF is a disturbing development (Figure 

3). These prices result from an oversupply 

that is being maintained by the active 

drilling of gas shales and the horizontal 

development of liquids-rich unconventional 

plays which produce high volumes 

of associated gas. This activity continues 

throughout the country and shows no sign 

of abating. 

Although oil prices are now the main 

driver in maintaining drilling activity in 

the State, Oklahoma remains strongly 

gas-prone with gas representing 81% of 

our BOE production. Given the dominance 

of gas in Oklahoma industry earnings, 

State gross-production tax income 


can never fully recover until prices reach 

a level where gas-targeted drilling again 

becomes economically viable. There are 

prolific shale-gas plays across the U.S., 

and like the Woodford in Oklahoma, these 

continue to be drilled (and produced) in 

an already glutted market. Price predictions 

are impossible, but certainly until 

the bulk of prospective shale-gas acreage 

is ‘held by production,’ which will afford 

operators the luxury of drilling infill wells 

only when prices are higher, there is little 

chance that prices will significantly recover. 

Languishing gas prices, high oil prices, 

and the expectation that these will continue 

has again pushed oil-targeted drilling 

higher. In 2011 gas drilling fell another 7% 

with oil rising by the same amount (Boyd, 

2011). Technically oil now accounts for 

over half of all drilling in the State (Figure 

4). However, if horizontal gas wells that 

were drilled to maximize oil/condensate/ 

NGL production are excluded, this disparity 

would be even more pronounced. As 

will be discussed, with even the oiliest 

plays producing mostly gas and many of 

the ‘gas’ plays producing substantial volumes 

of hydrocarbon liquids, well classification 

becomes problematic. However, 

acreage expiration issues aside, it appears 

there are very few wells being drilled in 

Oklahoma today that are not relying on 

liquids production for economic viability. 

Water-injection and disposal-well drilling 

represents about 9% of all 2011 drilling 

(Figure 4) - a slight increase over previous 

years. High-rate water-disposal wells,

which invariably target the Arbuckle 

Group, are a prerequisite for production 

in all of the State’s horizontal plays. In 

fact, future drilling activity can often be 

gauged based on the number and location 

of disposal-well drilling permits. Dry and 

junked holes accounted for an additional 

7% of 2011 drilling. Although a large percentage 

of the wells drilled in Oklahoma 

were classified as ‘New Field Wildcats,’ 

because they are targeting unconventional, 

blanket reservoirs, this is something of 

a misnomer. (The term ‘unconventional’ 

is used here to denote reservoirs in which 

the permeability is too low to permit 

fluid separation.) The overall 93%+ success 

rate that the industry has enjoyed is 

comparable to previous years and shows 

that drilling throughout Oklahoma continues 

to be overwhelmingly developmental 

(Figure 4). Even for isolated horizontal 

wells where economic risk is probably the 

greatest, the chance of a non-producing 

dry hole is usually less than the mechanical 

risk associated with drilling the well. 

Figure 4. Oklahoma 2011 well completion results (for wells reported through January 1, 2012). 

Data from IHS Energy (2012). 

Figure 5. Oklahoma oil and gas production on a barrel of oil equivalency (BOE) from 2005 to 2011. Early data from Soltani, 2012. Later data taken from 

E.I.A., 2012. 




Figure 6. Oklahoma annual well completions comparing vertical and horizontal drilling from 2002 to 2011. Note the resiliency of horizontal drilling 

despite lower prices over the last three years. Data from IHS Energy (2012) through January 1, 2012. 

Active Woodford Shale drilling, with 

279 horizontal completions registered so 

far in 2011, combined with contributions 

from other high GOR horizontal plays, is 

projected to increase State gas production 

in 2011 by 46 BCF (7.7 MMBOE) over 

2010 (Figure 5). A continued concentration 

on oil/condensate-targeted drilling 

has also increased ‘oil’ production by almost 

2 MMBO and maintained a trend of 

increasing production that began in 2008. 

Oil production in Oklahoma declined 

continuously from the end of the drilling 

boom in 1984 until 2005. Since then higher 

prices have fueled increases in both vertical 

development and horizontal drilling 

that have increased production by 16%, or 

over 10 MMB per year. 


Reporting delays, which sometimes manifest 

as gross underreporting of production, 

have forced the use of the Energy Information 

Administration (EIA) data for annual 

State production volumes beginning 

in 2008 (Figure 5). The EIA develops 

production statistics from survey forms 

that are submitted by respondents on a 

monthly basis. These are combined with 

data from ‘other sources’ in order to estimate 

total State production. Although this 

is something of a black box, EIA volumes 

make more sense based on documented 

drilling and completion activity. They 

have online data through July, 2011 while 

the OCC as of this writing has yet to publish 

2010 production (E.I.A., 2012). OCC 

and EIA annual production numbers have 

diverged from near-agreement in 2007 to 

a difference of 3% in oil and 11% in gas 

in 2009. Such discrepancies make year-toyear 

projections impossible. 

Overall, the 876 wells thus far registered 

as having begun production in 2011 

have contributed about 23 thousand barrels 

(MBO) and 608 million cubic feet 

(MMCF) per day. This represents about 

12% of both State oil and State gas production, 

but reporting lags ensure that this 

percentage will be extremely conservative. 

The vast bulk of this new production 

is due to horizontal drilling. Despite the 

industry’s success in finding and producing 

oil and gas in 2011, continued declines 

in many older wells reduces the annual

ise in overall production to about 3%. 

This underscores the need for continuous, 

high levels of drilling activity in order to 

maintain production levels. On a BOE 

basis natural gas production is four times 

that of oil (Figure 5), but the price differential 

inflates oil’s value to 43% of the total. 

Although this makes the industry and 

the State less dependent on natural gas, its 

price remains the key factor in the overall 

economic health of both. 

Reporting delays necessitate a revision of 

historic State drilling statistics each year. 

Since January 1, 2011 987 additional completions 

were registered for 2010 and 163 

were added to 2009. In fact, in this year’s 

update it was necessary to add new completions 

to the totals registered for every 

year since 2002. Such delays and the fact 

that the proportion of reported and ‘not- 

yet-reported’ wells is inconsistent from 

year to year make annual comparisons of 

drilling activity difficult. As in previous 

years, to reduce the impact of reporting 

delays all completion numbers for 2011 

were increased by one third. Total completions 

in 2011 registered through January 

1, 2012 were slightly above those reported 

for 2010 at the same time last year. 

Although both year’s well counts will 

continue to rise, it appears that the number 

of completions that will ultimately 

be registered in 2011, despite the higher 

proportion of (longer to drill) horizontal 

completions, will be greater than those for 

2010 (Figure 6). 

From 2002 through 2008 overall drilling 

activity generally increased, but this 

trend ended abruptly when prices fell at 

the end of 2008. The reduction in drilling 

was especially pronounced for vertical 

wells, which fell by half in 2009 (Figure 

6). The number of horizontal wells drilled 

also fell that year, but as a proportion of all 

drilling the rise in horizontal drilling was 

remarkably consistent until 2011 (Figure 

7). The jump in the percentage of horizontal 

well completions last year was as 

much due to less vertical activity as more 

horizontal. Since 2002 horizontal completions 

in Oklahoma have risen from 4% to 

41% of the total number of completions, 

and these now represent 62% of the total 

footage drilled in the State. 

Hundreds of companies drilled wells in 

2011, but Chesapeake Operating continues 

to be the most active operator (Figure 8). 

The 184 completions registered through 

January 1 st are comparable to those assigned 

to them in last year’s report, and 

Figure 7. Oklahoma annual horizontal drilling as a percentage of total completions from 2002 to 2011. In terms of footage drilled 2011 horizontal wells 

accounted for nearly two thirds of State drilling. Data from IHS Energy (2012) through January 1, 2012. 




Figure 8. Top five operators in Oklahoma in 2011 based on the number of completions registered through January 1, 2012. Data from IHS Energy (2012). 

these represent over 8% of all drilling in 

the State. Chesapeake is active in almost 

every part of Oklahoma, but their drilling 

in 2011 was dominantly horizontal and 

was concentrated in the Desmoinesian 

Granite Wash, the Mississippian, and the 

Cleveland plays in the western part of the 

State. 

The remaining top operators in the State 

are much more focused in their drilling. 

Based on completion numbers the second 

most active operator in 2011 was Citation 

Oil and Gas who drilled or recompleted 

129 vertical, shallow, oil development 

wells and injectors in southern Oklahoma, 

mostly in Sho-Vel-Tum, Fitts, and Healdton 

Fields. SandRidge’s drilling activity 

was restricted exclusively to horizontal 

wells in the Mississippian play in Woods, 

Grant and Alfalfa Counties, which included 

37 water-disposal wells. Devon Energy 

was primarily focused on horizontal development 

of the Woodford Shale, mostly in 

their ‘Cana’ play located on the northeastern 

shelf of the Anadarko Basin. Round- 


ing out the top five operators in 2011, New 

Dominion, another perennial member of 

the top-five-operators club, continues to 

focus exclusively on Misener/Hunton dewatering 

projects, most of these located in 

Seminole County (Figure 8). 

Horizontal Drilling 

The petroleum industry in Oklahoma today 

is concentrating on low-permeability 

reservoirs that horizontal drilling and 

completion technology have made into 

attractive targets (Figure 9). This activity 

began in earnest about ten years ago 

with production from horizontal wells in 

the Hartshorne coal in the Arkoma Basin. 

Drilling here accelerated through the early 

part of the decade and was augmented 

by the Misener/Hunton dewatering play, 

which is located mostly in central Oklahoma. 

These two plays were followed in 

2006 by the Woodford Shale, which has 

seen development in the western Arkoma, 

Ardmore, and eastern Anadarko Basins. 

There is now an ever-lengthening list of 

other reservoirs that lend themselves to 

horizontal drilling and completion techniques. 

In addition to dozens of lesser 

targets, the most active include the Cleveland, 

Desmoinesian Granite Wash, and 

now the Mississippian, whose potential 

prospective area, which extends from 

northern Oklahoma through central Kansas, 

could become the largest of them all 

(IHS Energy, 2012). 

Horizontal drilling plays are attractive for 

many reasons. Because they exist in lowpermeability 

reservoirs in which fluid separation 

is not possible, the accumulations 

are continuous and the geological risk of a 

dry hole is essentially zero. Blanket reservoirs 

that are often quite thick also contain 

exceedingly large in-place gas and/or oil 

volumes, making the potential target large. 

Relatively small drainage areas, even after 

extensive fracture stimulation, means 

that many wells must be drilled in order 

to adequately develop such reservoirs. Although 

restricted drainage is not normally

Figure 9. Major Oklahoma horizontal drilling plays (> 100 completions) from 2002 to 2011. Data from IHS Energy (2012) through January 1, 2012. All 

registered 2011 completion numbers increased by one third to account for reporting delays. 

an attractive characteristic, this allows 

companies to book proved undeveloped 

reserve volumes that are two to seven 

times those booked for the first well in the 

drilling unit. The result is a ‘dream scenario’ 

for large operators whose regional leasing 

programs have captured hundreds of 

thousands or even millions of net mineral 

acres. With drainage areas established, 

locations are permitted and wells drilled 

based on lease expiration. Large numbers 

of dedicated drilling rigs are then able to 

turn reserve bookings into an assemblyline 

process in which the primary risk is 

mechanical. The thousands to tens-ofthousands 

of development locations generated 

from this ‘exploratory’ drilling create 

proved-undeveloped reserve volumes 

that quickly become astronomical. 

However, even horizontal plays are pricesensitive. 

Early production declines are 

very steep and drilling, operational (including 

water disposal) and acreage costs 

are high. Although most horizontal plays 

have ‘sweet spots’ that will remain economic 

in almost any price environment, 

based on the data at hand most of the prospective 

areas appear to be economically 

marginal in all but higher-price scenarios. 

With the fall in natural gas prices in late 

2008 operators have been forced to focus 

on horizontal plays that are more liquidsrich, 

which includes oil, condensate, and 

natural gas liquids (NGLs). However, because 

the targeted reservoirs have exceedingly 

low permeability, even the most liq- 

uids-rich horizontal plays produce mostly 

gas (Figure 10). This preponderance of 

natural gas, combined with its low price, 

makes it appear that operators have foregone 

short-term economics in favor of a 

strategy of holding acreage by production. 

Development drilling on this acreage can 

then wait until prices rise above whatever 

economic threshold the operator deems 

necessary to justify future activity. 

Almost every significant productive reservoir 

in the State has been drilled horizontally 

somewhere, but some have been 

systematically exploited in well-defined 

area(s) which can be described as geologic 

plays. Three of these, while still producing, 

are largely inactive in terms of drilling. 




Figure 10. Oklahoma major horizontal play cumulative production in MMBOE. Even the most hydrocarbon liquids-rich horizontal plays produce 

primarily gas. Natural gas liquid (NGL) production is not taken into account. Data from IHS Energy (2012). 

Chesapeake utilized horizontal-drilling 

technology in the mid- to late-1990’s to 

pursue mostly oil in the Sycamore carbonate 

in southern Oklahoma. Most of these 

wells are located in Sho-Vel-Tum Field 

and the Golden Trend. Another largely inactive 

horizontal play was made by EOG 

Resources in the Panhandle in western 

Texas County. Here they drilled about 70 

horizontal gas wells between 2000 and 

2003 in the Council Grove, mostly in Unity 

SW and Guymon-Hugoton Fields. In an 

aggressive dewatering project that utilizes 

horizontal drilling, New Dominion has 

targeted the Arbuckle in the Oklahoma 

City Field. Here they have drilled 55 horizontal 

laterals from 17 surface locations 

and are disposing the water into the Arbuckle 

on the downthrown side of the field 

fault (Boyd, 2010). 

Using an arbitrary 100-well cutoff, there 

are six ‘major’ horizontal plays in Okla- 


homa with all but one still active. In addition, 

there are others (Marmaton, Tonkawa 

and Cherokee) that appear destined to 

reach this milestone soon. Drilling statistics 

for the most active horizontal plays 

over the last ten years are shown in Figure 

9. [The 2011 totals for each of those 

listed have been increased by 33% in an 

attempt to account for the reporting delays 

described previously.] Although the 2011 

projections are probably still conservative, 

the graph should be indicative of the 

direction that activity in these plays is taking. 

Figure 11 shows the productive areas 

occupied by the six ‘major’ horizontal 

plays at the end of 2010 and the completions 

that were added to these and all other 

reservoirs in 2011. In the last month reported, 

usually between July and September 

of 2011, Oklahoma’s 5,030 producing 

horizontal wells were making 35 MBO + 

1,819 MMCF per day. Even this under-reported 

volume represents 18% of State oil 

production and 35% of gas. The six major 

horizontal plays account for over 90% of 

this production. (All production cited are 

from IHS Energy, 2012.) 

Hartshorne Coal 

Located in the Arkoma Basin, Hartshorne 

coalbed methane has been exploited with 

horizontal wells for more than a decade. 

Low natural gas prices and negligible liquids 

production have depressed drilling 

activity in this play since the fall in natural 

gas prices in 2008. Although still the largest 

horizontal play with 1,691 wells, with 

only seven registered completions in 2011 

the Hartshorne coal has disappeared as 

an active play. There appears to be ample 

room to expand this play eastward (Figure 

11), but only a major increase in gas prices 

will see this area developed. The 1595 

actively producing horizontal Hartshorne

coal wells have an average cumulative recovery 

of 249 MMCF and a current rate of 

60 MCF per day. 

Woodford Shale 

The next largest horizontal drilling play in 

the State, and the one that is still by far 

the most active, is the Woodford Shale. In 

only six years it now boasts 1,639 producing 

wells of which 279 have been registered 

thus far for 2011. Although the decline 

in gas prices has pushed most Woodford 

drilling into areas with higher liquid 

yields, activity remains brisk (Figure 9). 

Of the three primary producing trends, 

the western Arkoma Basin accounts for 

nearly three quarters of all Woodford 

wells. Here most of the 2011 activity was 

in and around areas of established production, 

which has linked several isolated 

producing areas and appears destined to 

become contiguous through central Pittsburg 

County (Figure 11). The most active 

operators in the Arkoma Basin in 2011 

were Newfield Exploration, XTO Energy 

and Devon Energy. The 1,119 horizontal 

Woodford producers in this area have 

average cumulative production of 897 

MMCF and a current rate of 751 MCF 

per day. Oil and condensate production in 

most of this area is negligible. 

The most active 2011 Woodford drilling 

occurred in the producing area pioneered 

by Devon Energy in the northeastern 

Anadarko Basin. This productive area has 

continued to expand from western Canadian 

County into southern Blaine and 

northern Caddo Counties. Previously isolated 

pods of production in southeastern 

Dewey County have merged and appear 

poised to link with the main area. Expansion 

along strike to the southeast through 

Grady County is also taking place, but 

this has not yet become as active. Devon 

Energy was by far the most active operator 

in this area in 2011, drilling over 

half of all wells. There are now 346 horizontal 

Woodford wells producing in the 

Anadarko Basin and these have average 

cumulative production of 662 MMCF and 

7 MBO. Average per well production for 

the last reported month across this part of 

the play was 960 MCF + 11 BO per day. 

Although only wet gas production is reported, 

NGL yields in this play are significant 

with reported Btu contents as high as 

1350 per MCF. 

A third major concentration of horizontal 

Woodford Shale production is located 

along the northern edge of the Ardmore 

Basin in Carter, Johnston, and Marshall 

Counties where there is now a trend about 

40 miles long. In 2011 this was the least 

active part of the play with no major extensions 

to the previously established producing 

area (Figure 11). In the Ardmore 

Basin the most active horizontal Woodford 

operator is XTO Energy. The 111 producing 

wells registered in this area have average 

cumulative production of 662 MMCF 

and 7 MBO. Average per well production 

in the last reported month was 960 MCF + 

11 BO per day. 

Misener/Hunton 

Dewatering has found its greatest application 

in the Hunton (Misener/Hunton) 

reservoir where over 1,322 horizontal 

wells have now been drilled. This play has 

remained consistently strong, with over 

100 wells drilled in each of the last seven 

years (Figure 9). Production through reservoir 

dewatering has been pursued in this 

reservoir interval in a number of areas. 

Aside from a handful of wells in the Edmond 

West Field area, the bulk of recent 

activity has again concentrated in central 

Oklahoma mostly in and around Seminole, 

Lincoln, and Okfuskee Counties. 

As was the case last year, New Dominion 

was the dominant operator in this play, accounting 

for more than half of all horizontal 

Misener/Hunton wells drilled in 2011. 

The second most active operator was 

OEX-1 LLC, who has 20 wells registered 

thus far. Activity for both operators was 

mostly relegated to previously established 

areas of production. Because this play requires 

a major drop in reservoir pressure 

before significant hydrocarbons are produced, 

a process that can take years, the 

productivity of new wells or areas cannot 

be ascertained based on initial potential 

tests. This is why none of these has ever 

made the annual list of significant wells. 

Horizontal Hunton and Misener/Hunton 

wells have produced about 5 MMBO and 

283 BCF, generating an average recovery 

per completion of 10 MBO + 551 MMCF 

(Figure 10). 

Cleveland 

Unlike the first three horizontal plays, 

the remaining have significant liquids 

production and so have tended to benefit 

from the relative strength of oil prices and 

their continued rise (Figure 2). Horizontal 

Cleveland Sandstone drilling, which fell 

by a third in 2009, is at an all-time high 

with at least 90 completions projected 

for 2011. Like last year, recent activity 

has seen a major expansion of the older 

productive areas and the addition of new 

areas of production. 

The main productive area in Ellis County, 

which continues into Lipscomb and Ochiltree 

Counties in the Texas Panhandle, 

has recently been extended into northern 

Roger Mills County. The satellite area that 

began in southwestern Dewey has continued 

to grow and has now moved well into 

Custer County. Based on drilling trends 

it appears that these two productive areas 

may meet in the future. An isolated pod of 

horizontal Cleveland production in northern 

Logan County also saw the addition of 

two wells in 2011 (Figure 11), but its economic 

viability remains in doubt. Despite 

the high oil volumes registered on initial 

tests and their general classification as oil 

wells, on a BOE basis horizontal Cleveland 

production is two-thirds natural gas 

(Figure 10). To date the play’s cumulative 

production in Oklahoma is 7.7 MMBO + 

92 BCF (15.4 MMBOE), giving the average 

well a cumulative production of 29 

MBO + 347 MMCF. 

Granite Wash 

There are several reservoirs called ‘Granite 

Wash’ that are being explored for and 




103° 

37° 

6N 

5 

3 

2 

1N 

4 

103° 

developed in the Anadarko Basin. These 

reservoirs span nearly the entire Pennsylvanian 

System through the lower Permian 

and are comprised of thick, low-permeability 

sediments shed from the Wichita 

Uplift located to the south. As such they 


1E 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 E 25 24 23 22 21 20 19 18 17 16 15 14 

102° 

101° 

CIMARRON TEXAS BEAVER 

102° 

EXPLANATION 

101° 

HORIZONTAL PLAY ACTIVITY 

2011 WELL MAJOR PLAYS FORMATION 

0 50 Miles 

0 50 Kilometers 

vary in lithology based on the formation 

that was exposed on the uplift at the time 

of deposition. ‘Granite Wash’ reservoirs 

have been produced from vertical wells 

for decades with varying levels of success, 

but the advent of horizontal drilling and 

2 

Other 

1 

Miss. Lime/Chat 

DM Granite Wash 

Cleveland 

Misener/Hunton 

Hartshorne 

Woodford 

23N 

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ELLIS 

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ROGER 

MILLS 

HARPER 

BECKHAM 

HARMON 

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4 

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GREER 

WOODWARD 

JACKSON 

99° 

DEWEY 

completion techniques has reduced the 

dry hole risk and made some enormously 

economic. 

The Desmoinesian Granite Wash horizontal 

play, located in the deepest part of the 

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WASHITA 

KIOWA 

HOLLIS BASIN 

Figure 10. Oklahoma major horizontal play cumulative production in MMBOE. Even the most hydrocarbon liquids-rich horizontal plays produce 

primarily gas. Natural gas liquid (NGL) production is not taken into account. Data from IHS Energy (2012). 

3 

7 

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TILLMAN 

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ANAD 

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WICHITA 

UPLIFT 

CO

13 12 11 10 9 8 7 6 5 4 3 2 1W 1E 2 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25E 

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29N 

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AJOR 

ALFALFA 

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BLAINE 

CADDO 

MANCHE 

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COTTON 

98° 97° 96°95° 

GRANT 

GARFIELD 

KINGFISHER 

34° 

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ARKO BASIN 

& SHELF 

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CANADIAN 

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GRADY 

STEPHENS 

JEFFERSON 

98° 

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LOGAN 

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OKLAHOMA 

ARDMORE 

BASIN 

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KAY 

NOBLE 

PAYNE 

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CLEVELAND 

GARVIN 

CARTER 

LOVE 

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PAWNEE 

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LINCOLN 

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POTTAWATOMIE 

MURRAY 

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Anadarko Basin, is by far the most important 

of the ‘Granite Wash’ reservoirs 

to date. Starting in north-central Washita 

County, completion numbers grew by 

a third in the last year. Chesapeake was 

again the dominant operator in this play, 

14 

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MARSHALL 

SEMINOLE 

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OSAGE 

PONTOTOC 

JOHNSTON 

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CREEK 

OKFUSKEE 

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ARBUCKLE 

UPLIFT 

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CHEROKEE 

PLATFORM 

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COAL 

HUGHES 

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BRYAN 

TULSA 

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OKMULGEE 

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WASHINGTON 

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ATOKA 

NOWATA CRAIG 

ROGERS 

PUSHMATAHA 

CHOCTAW 

MAYES 

OTTAWA 

WAGONER CHEROKEE 

ADAIR 

PITTSBURG 

MUSKOGEE 

McINTOSH 

LATIMER 

HASKELL 

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accounting for nearly two thirds of the 

2011 completions registered thus far. In 

addition to development within the main 

producing area, recent drilling has expanded 

this core area another township 

west into Roger Mills County (Figure 11). 

15 

ARKOMA 

BASIN 

OUACHITA 

MOUNTAINS 

UPLIFT 

DELAWARE 

OZARK 

UPLIFT 

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Activity was also brisk along the Texas 

border, but efforts to connect these two 

areas with economic production appear to 

have failed so far. 

Vertical wells have produced Desmoine- 




sian Granite Wash since the mid-1980s, 

but horizontal production only began in 

April 2007 (Figure 9). Through August of 

last year the wells in this play registered 

an average recovery of 727 MMCF and 55 

MBC, with most of these on line for less 

than two years. Having the highest average 

liquids production for any horizontal 

play in the State, it is notable for spectacular 

rates on initial potential tests and wells 

with payouts often measured in months. 

Although its high condensate yield makes 

this horizontal play particularly attractive, 

like the Cleveland, on a BOE basis it is 

still about two-thirds gas (Figure 10). 

Although the Desmoinesian Granite Wash 

is the only horizontal wash play with a 

significant production history, there are 

several others that appear destined to expand. 

Naming conventions make these 

difficult to distinguish from non-wash 

reservoirs, and some may overlap with 

reservoirs to the north. However, wells 

located in Beckham, Washita, Caddo, and 

southern Roger Mills and Custer Counties 

likely have a southern source and so could 

be called ‘wash’ reservoirs. In addition to 

those identified as Desmoinesian (Series) 

and Granite Wash (which is assumed to 

also be Desmoinesian Granite Wash), this 

area includes reservoirs identified by operators 

as Atoka, Skinner, Cherokee, Missouri, 

Pennsylvanian Missourian, Hoxbar, 

Marchand, and Hogshooter. Reservoirs 

using the same names produce in horizontal 

wells in northern Roger Mills and Ellis 

Counties, and although their productive 

characteristics are similar, these are probably 

sourced from the north and/or east 

and so are not true ‘wash’ reservoirs. 

Mississippian (Lime / Chat) 

A much more scattered horizontal play, 

but the one that has experienced the greatest 

drilling surge in the last year, is targeting 

what is identified as the Mississippian 

Lime and Chat. These are different 

reservoirs, but are combined here due to 

inconsistent naming. The Chat produces 

horizontally mostly in Osage and Kay 

Counties and this part of the play appeared 


to be relatively quiet in 2011. It is a thin, 

siliceous zone of variable reservoir quality 

that intermittently develops on top of 

the Mississippian Lime. Like the Mississippian 

Lime beneath, it has produced for 

decades from vertical wells. It can now 

be identified seismically, and horizontal 

wells drilled on seismic anomalies have 

allowed operators to maximize exposure 

to the Chat. Because it has natural permeability 

wells are usually untreated. 

The Mississippian Lime is a regional carbonate 

found across most of the State. It 

has produced from vertical wells for decades, 

albeit usually marginally. Horizontal 

wells have the potential to make this 

reservoir economic over a much wider 

area. Although it can develop porosity and 

permeability, reservoir quality tends to be 

poor. It is often fractured, and horizontal 

drilling affords the opportunity to enhance 

natural fractures with multi-stage acid 

fracture stimulations. The Mississippian 

Lime is thick and oil-prone across much 

of the northern half of the State, giving 

this formation regional prospectivity. Given 

its wide extent, the play has the potential 

to become the largest and perhaps the 

most productive horizontal drilling play in 

Oklahoma (Figure 11). 

A total of 157 horizontal Mississippian 

wells have so far been registered for 2011, 

bringing the total number of completions 

to 285. Recent wells were mostly clustered 

around the main area of production 

located in Woods and Alfalfa Counties and 

this activity has moved across the border 

into Kansas. The core area is dominated 

by Chesapeake and SandRidge, each of 

whom have leaseholds exceeding one million 

net acres. The core productive area 

is expanding to the east and south with 

isolated activity as far east as Payne and 

Pawnee Counties. Although 241 wells are 

now on production, the vast majority have 

been online for less than a year. Average 

cumulative per well recoveries now stand 

at 13 MBO + 113 MMCF with production 

in the last reported month at 25 BO + 

306 MCF per day. Although it is the oiliest 

of the horizontal plays, on a BOE basis 

Mississippian production is still 60% gas 

(Figure 10). 

The Oklahoma oil and gas industry has 

applied horizontal-drilling technology to 

dozens of other reservoirs across the State 

and will continue to test the limits of where 

this can be applied. There are sweet spots, 

but a large proportion of the horizontal 

wells drilled thus far appear to be marginal 

to clearly sub-economic. However, low 

productivity can be as much due to the 

manner in which the wells are drilled and 

completed as any inherent geological factors. 

The learning curve from first (often 

marginal) production to more consistent, 

economic development is a process measured 

in years. There are a number of reservoirs 

that were not discussed that, based 

on initial potentials, are showing promise. 

Wells tapping these reservoirs, which are 

classified as ‘Others’ in Figure 9 and are 

shown as black pluses in Figure 11, may 

develop into larger horizontal-drilling 

plays in the future. 

Significant Wells in 2011 

The following is a list of what are believed 

to be among the most significant 

wells registered for Oklahoma in 2011. 

Although all were registered in the past 

year, due to reporting delays, some have 

earlier completion dates. The wells listed 

were identified from a weekly review of 

the IHS Energy EnergyNews on Demand 

Midcontinent activity reports released 

online throughout the year. An initial list 

of 152 candidates compiled from this 

publication was distilled to a final total 

of 15. Such a list is subjective and may 

miss wells that could eventually become 

noteworthy. Due to confidentiality issues, 

wells that may be notable for technical 

reasons will probably be missed. For instance, 

those that confirm some new type 

of trapping style or proved the benefit of a 

new drilling or completion technique will 

be difficult to identify until information is 

disseminated years from now. 

Horizontal wells have occupied a progres-

sively larger share of the significant well 

listings each year. In 2010, and now 2011, 

they comprise all of the ‘all-star’ wells in 

this report. Those listed here have either 

significantly expanded what appears to 

be economic production in an established 

horizontal play or in some way constrained 

its ultimate extent. To keep this 

listing to a manageable size, in some cases 

related nearby wells were added to the 

discussion. Wells with production histories 

are given precedence over those with 

only impressive initial potential tests and, 

where available, the volumes reported are 

given. Please refer to Figure 11 for orientation 

during the following discussion. 

1) Sec. 13-3N-21ECM (Beaver County): 

In one of the State’s most active horizontal 

drilling plays QEP Energy extended Marmaton 

production two miles to the northwest 

with the completion of their Bobbitt 

Trust #3-13H well. As well as expanding 

the productive area, this well has also established 

a new highest initial potential 

with a daily rate of 1,063 BO per day. No 

gas, water, or stimulation was recorded for 

this well, which was completed in a 4,508’ 

lateral located at a true vertical depth 

(TVD) of 6,000’. 

2) Sec. 6-1N-20ECM (Beaver County): 

In a related development, Unit Petroleum 

made a horizontal Marmaton completion 

in the State of Oklahoma #1-H that is 15 

miles west of the main play. This well is 

located on the southern limit of a small 

pod of vertical Marmaton wells assigned 

to the Camrick District that were drilled 

in 1970 and 1971. Since that time the five 

wells in Section 6 have produced about 

172 MBO. This new horizontal well had 

an initial potential on pump of 284 BO 

(38 O API) + 93 MCF + 1,740 BW per day 

from a 2,218’ lateral at a TVD of 5,890’. 

It was fracture stimulated with 650,000 

pounds of sand. 

3) Sec. 4-14N-24W (Roger Mills County): 

Classified for now as part of the same 

horizontal Marmaton play located to the 

north, operators drilled about two dozen 

wells in southern Ellis County and have 

now pushed production into central Roger 

Mills County. Although here it may have 

a southern provenance, making it a Marmaton 

‘wash’, it is still simply identified 

as Marmaton. The Cordillera Energy Galileo 

#2-4HA had an initial potential of 367 

BO + 5.36 MMCF per day with no water 

reported. The well has a 2,200’ lateral located 

at a TVD of 11,150’. Cordillera has 

reported that the NGL yield from the gas 

at this well is about 93 barrels per MMCF, 

giving it nearly 500 barrels of NGL production 

initially. This is comparable to 

the yield reported for Marmaton wells in 

Ellis County. The number of horizontal 

Marmaton wells nearly tripled in 2011 

with Unit Petroleum and EOG Resources 

operating most of them. With a total of 86 

completions registered thus far this play 

will undoubtedly become one of the ‘major’ 

horizontal plays in next year’s report. 

4) Sec. 23-26N-24W (Harper County): In 

another horizontal play that will probably 

reach the 100-well hurdle and become 

‘major’ in the next year or two, Cherokee 

completions also more than tripled 

in 2011. The 45 completions in 2011 are 

mostly scattered in three areas in southern 

Roger Mills, southern Ellis, and western 

Harper Counties. Apache completed their 

Zoldoske #4-23H for 525 BO (45 O API) 

+ 681 MCF + 117 BW per day. This well, 

which is the southernmost in the Harper 

County trend, shows that this play is far 

from defined. The well was completed in a 

4,482’ lateral at a TVD of 6,750’ and acidfraced 

in ten stages with about 1.2 million 

pounds of sand. In six months this well 

produced about 31 MBO + 77 MMCF 

with a rate in the last complete month of 

117 BO + 3.0 MMCF per day. 

5) Sec. 17-11N-21W (Beckham County): 

In a major westward extension of liquidsrich 

Desmoinesian Granite Wash production, 

Apache drilled a pair of excellent 

wells from the same surface location. Both 

completed in June 2011, the Smith 1-16H 

and 1-17H are virtual twins with initial 

potentials of 1,115 BC + 12,634 MCF + 

596 BW and 1,095 BC + 12,582 MCF + 

554 BW per day. Both wells have a TVD 

of about 13,000’ and 4,000’ laterals that 

were fracture stimulated with 3.1 to 3.3 

million pounds of sand. The heart of the 

play remains in Washita County, but these 

wells are the first to establish high liquids 

production in Beckham County, which until 

now has been dominantly gas. The two 

wells have produced 564 and 574 MMCF 

in less than two months with a combined 

recovery of 34 MBC. In the last complete 

month each well was producing about 11.6 

MMCF per day with a combined daily 

rate of 1,082 BC. Although Desmoinesian 

Granite Wash production extends westward 

into the Texas Panhandle, the eastern 

limit of this play seems to be anchored in 

the center of township 11N-16W. It is not 

known if this limit is geological or lease 

related, but high condensate-yield wells 

have been drilled by Chesapeake right up 

to this limit. 

6) Sec. 14-11N-23W (Roger Mills County): 

Along the trend of the Desmoinesian, 

Hogshooter and other horizontal ‘Granite 

Wash’ plays operators have been drilling 

wells targeting what they are calling 

Missouri Granite Wash or Cottage Grove 

sand. The most notable of these wells was 

drilled by Crawley Petroleum. The Moore 

#5-14H had an initial potential of 1,485 

BO + 5,717 MCF + 710 BW per day in a 

reservoir identified as the Cottage Grove 

sand. This well has a 5,260’ lateral at a 

TVD of 11,322’ that was fraced using 

about 2.4 million pounds of sand. 

7) Sec. 11-16N-20W (Dewey County): 

Horizontal Tonkawa completions, which 

doubled in 2011, have historically been 

situated in Roger Mills and southern Ellis 

Counties. 2011 saw a major westward 

development of the play into southwestern 

Dewey County. Chesapeake drilled what 

appears to be the best of the nine wells 

in this area with their Lauder #1-11H. 

Completed in a 4,260’ lateral at a TVD of 

8,240’ the well had an initial potential on 

gas lift of 510 BO (46 O API) + 420 MCF + 

1,260 BW per day after a fracture stimulation 

that used 4.2 million pounds of sand. 

In four months of production this well, 

apparently choked back, has cumulative 




production of only 76 MMCF with an average 

rate of about 700 MCF per day with 

no liquids production noted. 

8) Sec. 33-14N-18W (Custer County): 

There are now over 300 horizontal Cleveland 

completions with 65 registered thus 

far for 2011. Most of the activity took 

place within established producing areas, 

but the most significant extension seems 

to be in central Custer County where 

Chesapeake now has four months of production 

history on a 2011 discovery. The 

SGD #1-33H was completed in April from 

a 4,483’ lateral at a TVD of 10,591’ with 

2.2 million pounds of sand. After an initial 

flowing potential of 547 barrels of 46 O 

API oil + 1,153 MCF + 1,102 BW per day 

it has produced 23 MBO + 60 MMCF. In 

the last reported month it was still producing 

at a rate of 124 BO + 300 MCF per 

day. Several additional wells have since 

been permitted in the area. 

9) Sec. 11-3N-5W (Grady County): What 

began as the Woodford Shale ‘Cana’ play 

in western Canadian County is spreading 

over an ever-widening swath of the eastern 

shelf of the Anadarko Basin. The core 

area, which now comprises the better part 

of a dozen townships in Canadian, Blaine 

and Caddo Counties, appears to have been 

extended to the extreme southern corner 

of the basin some 60 miles to the southeast. 

The Continental Resources Lambakis 

#1-11H had an initial potential from 

the Woodford of 5.4 MMCF + 160 BC per 

day with no water reported. The well was 

produced after a ten-stage fracture stimulation 

from a 4,200’ lateral at a TVD of 

15,128’. Continental has indicated that the 

gas from the Lambakis has a Btu content 

of 1,350 (~ 170 barrels NGL per MMCF) 

and is commanding a price of $6.25/MCF. 

In three and a half months of production 

the Lambakis made about 12 MBO + 319 

MMCF with a rate in the last complete 

month of about 100 BC + 4.2 MMCF per 

day. 

10) Sec. 32-18N-15W (Dewey County): 

The ‘Cana’ Woodford Shale play has also 

moved well into Dewey County with Dev- 


on drilling the two most northerly wells 

so far. Their Rauh #1-32H had an initial 

potential of 147 BO + 3,253 MCF + 908 

BW per day. The Btu content of the gas 

was not reported, but the NGL production 

will probably be at least double what is 

reported as the initial ‘oil’ rate. This well 

was completed from a 4,292’ lateral at a 

TVD of 11,677’ and a fracture treatment 

using 2.2 million pounds of sand. The 

best well in this extension of the play is 

the Continental Resources #1-2H Brown 

which was drilled about three miles southwest 

in Section 2-17N-16W. After an initial 

potential of 3,772 MCFPD this well 

produced 1.5 BCF in two years and was 

making about 1 MMCFPD in the last reported 

month (September, 2011). 

11) Sec. 34-26N-13W (Woods County): 

Eagle Energy recorded the highest initial 

potential of any horizontal Mississippian 

well with the completion of their Longhurst 

#3H-34. This well flowed 2,225 

barrels of 32 O API oil with 4,767 MCF + 

2,789 BW per day. Completed in a 3,615’ 

lateral at a TVD of 5,806’, it was acidfraced 

with 12,500 barrels of fluid and 

160,000 pounds of sand. This well is less 

than a mile west of another Eagle Energy 

well in section 35. Completed in 2010, 

the Mary Beth #1-H was completed in a 

2,307’ lateral (TVD – 5,807’) pumping 

at a rate of 50 BO + 318 MCF + 3,212 

BW per day. Oriented north-south like the 

Longhurst, the Mary Beth is shown as a 

Chat well completed with a 24,500 barrel 

‘acid-frac’ in which no proppant was reported. 

There are many examples of wildly 

different initial potentials in adjacent 

wells in the Mississippian, as well as other 

horizontal plays, but this is the largest 

seen thus far. The underlying cause is not 

known, and neither well has any recorded 

production, but this certainly highlights a 

pitfall in blanket reserve assignments to 

regional plays. 

12) Sec. 3-23N-4W (Garfield County): 

Establishing the highest horizontal Mississippian 

initial potential in the county, 

Plymouth Exploration completed their Sebranek 

#1-3H flowing at 1,031 BO (44 O 

API) + 1,327 MCF + 3,799 BW per day. 

This well was completed in a 3,302’ lateral 

at a TVD of 5,774’ with a nine-stage, 

750,000 pound acid-fracture stimulation. 

The Sebranek seems to confirm at least a 

step in a bridge that may eventually link 

the western and eastern Mississippian play 

areas. However, it is a direct offset to a 

2010 well, the Wicklund #1-34H Massie, 

that had an initial potential on pump of 90 

BOPD. This well produced only 6 MBO 

+ 12 MMCF in 17 months, with a rate in 

the last month of 6 BOPD. It is not known 

whether the drilling/completion technique 

or some geologic factor is responsible for 

this discrepancy. 

13) Sec. 22-23N-4E (Pawnee County): 

Territory Resources pushed horizontal 

Mississippian production nine miles 

northeast of Pablo Energy’s initial discovery 

(Ripley #1H-31) in this westernmost 

part of the play (Boyd, 2011). Their Beast 

#1-27H had an initial potential on pump 

of 585 barrels of 40 O API oil with 1,000 

MCF + 2,300 BW per day. In this area the 

TVD of the 3,689’ lateral was only 3,674’, 

which was stimulated with an acid frac 

treatment using 122,000 pounds of sand. 

The Beast produced 137 BOPD in its first 

month, but in its last month was down to 

44 BOPD. Cumulative production in four 

months is about 8 MBO with no reported 

gas. The Ripley well (Sec. 31-22N-4E), 

which began Mississippian horizontal activity 

in this part of the State, in 20 months 

has produced about 54 MBO with a last 

reported rate of 24 BOPD. It too has no 

reported gas production. 

14) Sec. 21-18N-3E (Payne County): A 

horizontal Woodford Shale well that is off 

the beaten track was drilled by Calyx Energy 

with their State WFD #16-1H. With 

a TVD of only 4,379’ the 3,700’ lateral 

was acid-fraced with 685,000 pounds of 

sand and had an initial potential on pump 

of 310 BO (36 O API) + 150 MCF + 1,500 

BW per day. A true Woodford oil well, this 

well does not yet have any reported production. 

15) Sec. 16-7N-17E (Pittsburg County):

Petroquest Energy pushed the main productive 

area of the horizontal Woodford 

Shale in the Arkoma Basin eastward with 

the drilling of several wells in 2011. The 

best of these, their Tonya #1-20H, came 

References Cited 

Baker Hughes, 2012, 2011 Average Rotary Drilling Rig Count, 

Accessed at: http://gis.bakerhughesdirect.com/Reports/StandardReport.aspx 

Boyd, D. T., 2010, Oklahoma 2009 Drilling Highlights, Shale 

Shaker, Vol. 60, No. 5 pp. 199-209. 

Boyd, D. T., 2011, Oklahoma 2010 Drilling Highlights, Shale 

Shaker, Vol. 61, No. 5 pp. 293-306. 

E.I.A. (Energy Information Administration), 2012, Annual 

Oklahoma Production of Crude Oil and natural Gas: Accessed 

January, 2012 http://www.eia.gov/dnav/pet/hist/LeafHandler. 

ashx?n=pet&s=mcrfpok1&f=a http://www.eia.gov/dnav/ng/ng_ 

prod_sum_dcu_sok_a.htm 

Chet 

Dan T. 

Wallace 

Boyd 

on for 6,293 MCF + 1,259 BW per day. 

The well was completed with a fracture 

stimulation using 2.6 million pounds of 

sand on a 4,993’ lateral located at a TVD 

of 8,653’. Although there is not yet any 

Biographical Sketch 

recorded production for these wells, they 

appear to be as good as any in the play and 

show that there is still ample room to expand 

horizontal Woodford Shale production 

in this part of the State. 

IHS Energy, 2012, Well Data supplied online by Petroleum 

Information/Dwights LLC dba IHS Energy Group, January 1, 

2012, all rights reserved. http://energy.ihs.com/ 

Northcutt, R. A.; and Campbell, J. A., 1995, Geologic provinces 

of Oklahoma: Oklahoma Geological Survey Open-File Report 

5-95. 

Soltani, Cameron, 2012 Oklahoma Corporation Commission, Oil 

and gas information: pricing data through July, 2011, accessed at: 

http://www.occeweb.com/og/ogmonthytd.pdf 

Williams, James L., 2012 WTRG Economics, Henry Hub Spot 

Natural Gas Price graph, accessed at: http://www.wtrg.com/daily/ 

oilandgasspot.html 

Dan Boyd is a petroleum geologist with the Oklahoma Geological Survey, where he 

has been employed since 2001. Dan received his Master of Science degree in geology 

from the University of Arizona in 1978. He spent the first 22 years of his career as an 

exploration and development geologist in the petroleum industry. From 1978 through 

1991 he worked on a variety of areas in the United States from Houston, Dallas, and 

Oklahoma City for Mobil Oil and Union Texas Petroleum. In 1991 he moved overseas, 

working in Karachi, Pakistan for four years and Jakarta, Indonesia for the following 

four. He returned with his family to the U.S. in 1999 with Arco (the successor to Union 

Texas) where, until Arco’s sale to BP, he worked the offshore Philippines from Plano, 

Texas. 

Since joining the OGS staff Dan has presented and published several reports on 

the history, status, and future outlook of the oil and gas industry in Oklahoma. He 

chaired the 2002 Symposium on Cherokee Reservoirs in the Southern Midcontinent 

(OGS Circular 108), and prepared and presented a workshop on the Booch gas play 

in southeastern Oklahoma (Special Publication 2005-1). His most recent study of oil 

reservoirs and recovery efficiencies (Shale Shaker May/June, 2008) demonstrates 

that large volumes of producible oil remain in the ground and that a major barrier to 

finding and producing this oil is shortcomings in State oil and gas data. Dan serves 

on the board of Energy Libraries Online (ELO) from a conviction that the long term 

success of the Oklahoma industry depends on improving both the completeness and 

accessibility of State oil and gas data. 


120 North Robinson, Suite 900 Center 

Oklahoma City, OK 73102

2011 Drilling Highlights - Oklahoma Geological Survey - University ...

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