Data and Analysis Archives - Page 6 of 22

Data driven discussions about gas extraction and related topics.

Water Use in WV and PA

April 4, 2014/by FracTracker Alliance

Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania

Report and summary by Meghan Betcher and Evan Hansen, Downstream Strategies; and Dustin Mulvaney, San Jose State University

The use of hydraulic fracturing for natural gas extraction has greatly increased in recent years in the Marcellus Shale. Since the beginning of this shale gas boom, water resources have been a key concern; however, many questions have yet to be answered with a comprehensive analysis. Some of these questions include:

What are sources of water?
How much water is used?
What happens to this water following injection into wells?

With so many unanswered questions, we took on the task of using publically available data to perform a life cycle analysis of water used for hydraulic fracturing in West Virginia and Pennsylvania.

Summary of Findings

Some of our interesting findings are summarized below:

In West Virginia, approximately 5 million gallons of fluid are injected per fractured well, and in Pennsylvania approximately 4.3 million gallons of fluid are injected per fractured well.
Surface water taken directly from rivers and streams makes up over 80% of the water used in hydraulic fracturing in West Virginia, which is by far the largest source of water for operators. Because most water used in Marcellus operations is withdrawn from surface waters, withdrawals can result in dewatering and severe impacts on small streams and aquatic life.
Most of the water pumped underground—92% in West Virginia and 94% in Pennsylvania—remains there, lost from the hydrologic cycle.
Reused flowback fluid accounts for approximately 8% of water used in West Virginia wells.
Approximately one-third of waste generated in Pennsylvania is reused at other wells.
As Marcellus development has expanded, waste generation has increased. In Pennsylvania, operators reported a total of 613 million gallons of waste, which is approximately a 70% increase in waste generated between 2010 and 2011.
Currently, the three-state region—West Virginia, Pennsylvania, and Ohio—is tightly connected in terms of waste disposal. Almost one-half of flowback fluid recovered in West Virginia is transported out of state. Between 2010 and 2012, 22% of recovered flowback fluid from West Virginia was sent to Pennsylvania, primarily to be reused in other Marcellus operations, and 21% was sent to Ohio, primarily for disposal via underground injection control (UIC) wells. From 2009 through 2011, approximately 5% of total Pennsylvania Marcellus waste was sent to UIC wells in Ohio.
The blue water footprint for hydraulic fracturing represents the volume of water required to produce a given unit of energy—in this case one thousand cubic feet of gas. To produce one thousand cubic feet of gas, West Virginia wells require 1-3 million gallons of water and Pennsylvania wells required 3-4 million gallons of water.

Table 1. Reported water withdrawals for Marcellus wells in West Virginia (million gallons, % of total withdrawals, 2010-2012)

Source: WVDEP (2013a). Note: Surface water includes lakes, ponds, streams, and rivers. The dataset does not specify whether purchased water originates from surface or groundwater. As of August 14, 2013, the Frac Water Reporting Database did not contain any well sites with a withdrawal “begin date” later than October 17, 2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.

As expected, we found that the volumes of water used to fracture Marcellus Shale gas wells are substantial, and the quantities of waste generated are significant. While a considerable amount of flowback fluid is now being reused and recycled, the data suggest that it displaces only a small percentage of freshwater withdrawals. West Virginia and Pennsylvania are generally water-rich states, but these findings indicate that extensive hydraulic fracturing operations could have significant impacts on water resources in more arid areas of the country.

While West Virginia and Pennsylvania have recently taken steps to improve data collection and reporting related to gas development, critical gaps persist that prevent researchers, policymakers, and the public from attaining a detailed picture of trends. Given this, it can be assumed that much more water is being withdrawn and more waste is being generated than is reported to state regulatory agencies.

Data Gaps Identified

We encountered numerous data gaps and challenges during our analysis:

All data are self-reported by well operators, and quality assurance and quality control measures by the regulatory agencies are not always thorough.
In West Virginia, operators are only required to report flowback fluid waste volumes. In Pennsylvania, operators are required to report all waste fluid that returns to the surface. Therefore in Pennsylvania, flowback fluid comprises only 38% of the total waste which means that in West Virginia, approximately 62% of their waste is not reported, leaving its fate a mystery.
The Pennsylvania waste disposal database indicates waste volumes that were reused, but it is not possible to determine exactly the origin of this reused fluid.
In West Virginia, withdrawal volumes are reported by well site rather than by the individual well, which makes tracking water from withdrawal location, to well, to waste disposal site very difficult.
Much of the data reported is not publically available in a format that allows researchers to search and compare results across the database. Many operators report injection volumes to FracFocus; however, searching in FracFocus is cumbersome – as it only allows a user to view records for one well at a time in PDF format. Completion reports, required by the Pennsylvania Department of Environmental Protection (PADEP), contain information on water withdrawals but are only available in hard copy at PADEP offices.

In short, the true scale of water impacts can still only be estimated. There needs to be considerable improvements in industry reporting, data collection and sharing, and regulatory enforcement to ensure the data are accurate. The challenge of appropriately handling a growing volume of waste to avoid environmental harm will continue to loom large unless such steps are taken.

Report Resources

Complete Report | Webinar

This report was written on behalf of Earthworks and was funded by a Network Innovation Grant from the Robert & Patricia Switzer Foundation.

This FracTracker article is part of the Water Use Series

Finding PA Department of Environmental Protection Data

March 28, 2014/by FracTracker Alliance

Data transparency is a major issue in the oil and gas world. Some states in the U.S. do not make the location or other details associated with wells easy to find. If one is looking for Pennsylvania data, however, the basic datasets are quite accessible. The PA Department of Environmental Protection (DEP) maintains several datasets on unconventional drilling activity in the Commonwealth and provides this information online and free of charge to the public. The following databases are ones that we commonly use to update our maps and perform data analyses:

1. Wells Drilled (Spudded)

2. Permitted Wells

3. O&G Violations

Search Criteria

Below are tips for how to search the PA DEP’s records and download datasets if you would like:

Dates

Date ranges must be entered in these databases in order to narrow down the search. We suggest starting with 1/1/2000 through current if you would like to see all unconventional activity to date.

County, Municipality, Region, and Operator

This criteria can be further refined by selecting particular counties, regions, etc.

Unconventional Only

For all datasets, “Unconventional Only – Yes” should be selected if you are only interested in the wells that have been drilled into unconventional shale formations and hydraulically fractured, or “fracked.”

“Unconventional” definitions according to PA Code, Chapter 78:

Unconventional well — A bore hole drilled or being drilled for the purpose of or to be used for the production of natural gas from an unconventional formation.

Unconventional formation — A geological shale formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be produced at economic flow rates or in economic volumes except by vertical or horizontal well bores stimulated by hydraulic fracture treatments or by using multilateral well bores or other techniques to expose more of the formation to the well bore.

Download

Once search criteria have been defined, click View Report to see the most up to date information compiled below. From there, the file can be downloaded in different formats, such as a PDF or Excel file.

Visit this page to see all of the oil and gas reports that the PA DEP issues.

North American Pipeline Proposal Map

March 14, 2014/by Ted Auch, PhD

By Ted Auch, PhD – OH Program Coordinator, FracTracker Alliance

With all the focus on the existing TransCanada Keystone XL pipeline – as well as the primary expansion proposal recently rejected by Lancaster County, NB Judge Stephanie Stacy and more recently the Canadian National Energy Board’s approval of Enbridge’s Line 9 pipeline – we thought it would be good to generate a map that displays related proposals in the US and Canada.

North American Proposed Pipelines and Current Pipelines

To view the fullscreen version of this map along with a legend and more details, click on the arrows in the upper right hand corner of the map.

The map was last updated in October 2014.

Pipeline Incidents

The frequency and intensity of proposals and/or expansions of existing pipelines has increased in recent years to accompany the expansion of the shale gas boom in the Great Plains, Midwest, and the Athabasca Tar Sands in Alberta. This expansion of existing pipeline infrastructure and increased transport volume pressures has resulted in significant leakages in places like Marshall, MI along the Kalamazoo River and Mayflower, AR. Additionally, the demand for pipelines is rapidly outstripping supply – as can be seen from recent political pressure and headline-grabbing rail explosions in Lac-Mégantic, QC, Casselton, ND, Demopolis, AL, and Philadelphia.¹ According to rail transport consultant Anthony Hatch, “Quebec shocked the industry…the consequences of any accident are rising.” This sentiment is ubiquitous in the US and north of the border, especially in Quebec where the sites, sounds, and casualties of Lac-Mégantic will not soon be forgotten.

Improving Safety Through Transparency

It is imperative that we begin to make pipeline data available to all manner of parties ex ante for planning purposes. The only source of pipeline data historically has been the EIA’s Pipeline Network. However, the last significant update to this data was 7/28/2011 – meaning much of the recent activity has been undocumented and/or mapped in any meaningful way. The EIA (and others) claims national security is a primary reason for the lack of data updates, but it could be argued that citizens’ right-to-know with respect to pending proposals outweighs such concerns – at least at the county or community level. There is no doubt that pipelines are magnets for attention, stretching from the nefarious to the curious. Our interest lies in filling a crucial and much requested data gap.

Metadata

Pipelines in the map above range from the larger Keystone and Bluegrass across PA, OH, and KY to smaller ones like the Rex Energy Seneca Extension in Southeast Ohio or the Addison Natural Gas Project in Vermont. In total the pipeline proposals presented herein are equivalent to 46% of EIA’s 34,133 pipeline segment inventory (Table 1).

Table 1. Pipeline segments (#), min/max length, total length, and mean length (miles).

Section	#	Min	Max	Mean	Sum
Bakken	34	18	560	140	4,774
MW East-West	68	5	1,056	300	20,398
Midwest to OK/TX	13	13	1,346	307	3,997
Great Lakes	5	32	1,515	707	3,535
TransCanada	3	612	2,626	1,341	4,021
Liquids Ventures	2	433	590	512	1,023
Alliance et al	3	439	584	527	1,580
Rocky Express	2	247	2,124	1,186	2,371
Overland Pass	6	66	1,685	639	3,839
TX Eastern	15	53	1,755	397	5,958
Keystone Laterals	4	32	917	505	2,020
Gulf Stream	2	541	621	581	1,162
Arbuckle ECHO	25	27	668	217	5,427
Sterling	9	42	793	313	2,817
West TX Gateway	13	1	759	142	1,852
SXL in PA and NY	15	48	461	191	2,864
New England	70	2	855	65	4,581
Spectra BC	9	11	699	302	2,714
Alliance et al	4	69	4,358	2,186	4,358
MarkWest	63	2	113	19	1,196
Mackenzie	46	3	2,551	190	8,745
Total	411	128	1,268	512	89,232^†

^† This is equivalent to 46% of the current hydrocarbon pipeline inventory in the US across the EIA’s inventory of 34,133 pipeline segments with a total length of 195,990 miles

The map depicts all of the following (Note: Updated quarterly or when notified of proposals by concerned citizens):

All known North American pipeline proposals
Those pipelines that have yet to be documented by the EIA’s Natural Gas Pipeline Network mapping team
EIA documented pipelines more accurately mapped to the county level (i.e., select northeastern pipelines)
The current Keystone XL pipeline and the Keystone XL expansion proposal rectified to the county level in Nebraska, South Dakota, Oklahoma, and Texas

We generated this map by importing JPEGs into ArcMAP 10.2, we then “Fit To Display”. Once this was accomplished we anchored the image (i.e., georeferenced) in place using a minimum of 10 control points (Note: All Root Mean Square (RMS) error reports are available upon request) and as many as 30-40. When JPEGs were overly distorted we then converted or sought out Portable Network Graphic (PNG) imagery to facilitate more accurate anchoring of imagery.

We will be updating this map periodically, and it should be noted that all layers are a priori aggregations of regional pipelines across the 4 categories above.

Imagery sources:

Northeast – Long Island Sound, Montreal to Portland, Westchester, Spectra Energy Northeast, Maritime Northeast-Algonquin-Texas Eastern, Delaware River Watershed, Northeastern accuracy of existing EIA data, New England Kinder Morgan, Spectra Energy-Tennessee Gas Pipeline Company (TGP)-Portland Natural Gas Transmission System (PNGTS)
Duluth to The Dakotas, NYMarc Pipeline, Mariner East, Millenium Pipeline Company, WBI Energy’s Bakken,
British Columbia – Enbridge, Spectra/BG, Coastal, Tanker Route
Midwest – ATEX and Bluegrass, BlueGrass, BlueGrass Pipeline,
TransCanada/New England – Portland, Financial Post,
Alaska Pipelines Historically
Rail projects and primary transport
Keystone Tar Sands – Canada (website no longer active), United States, Texas-Oklahoma
Gulf Coast – Florida
MarkWest Houston, Liberty, Liberty, Houston and Majorsville,
Texas Oklahoma – Granite Wash Extension,
Ohio – Spectra Energy, Enterprise Products, Kinder Morgan, Buckeye-Kinder Morgan-El Paso, Chesapeake Energy and AEP
The Rockies Express Pipeline (REX)

Reference

1. Krauss, C, & Mouawad, J. (2014, January 25). Accidents Surge as Oil Industry Takes the Train, The New York Times.

PA Production and Waste Data Updated

March 13, 2014/by Matt Kelso, BA

Every six months, the Pennsylvania Department of Environmental Protection (PADEP) publishes production and waste data for all unconventional wells drilled in the Commonwealth. These data are self-reported by the industry to PADEP, and in the past, there have been numerous issues with the data not being reported in a timely fashion. Therefore, the early versions of these two datasets are often incomplete. For that reason, I now like to wait a few weeks before analyzing and mapping this data, so as to avoid false conclusions. That time has now come.

This map contains production and waste totals from unconventional wells in Pennsylvania from July to December, 2013. Based on data downloaded March 6, 2014. Also included are facilities that received the waste produced by these wells. To access the legend and other map controls, please click the expanding arrows icon at the top-right corner of the map.

Production

Top 20 unconventional gas producers in PA, from July to December 2013. The highest values in each column are highlighted in red.

Table 1: Top 20 unconventional gas producers in PA, from July to December 2013. Highest values in each column are highlighted in red.

Production values can be summarized in many ways. In this post, we will summarize the data, first by operator, then by county. For operators, we will take a look at all operators on the production report, and see which operator has the highest total production, as well as production per well (Table 1).

It is important to note that not all of the wells on the report are actually in production, and not all of the ones that are produce for the entire cycle. However, there is some dramatic variance in the production that one might expect from an unconventional well in Pennsylvania that correlates strongly with which operator drilled the well in question. For example, the average Cabot well produces ten times the gas that the average Atlas well does. Even among the top two producers, the average Chesapeake well produces 2.75 times as much as the average Range Resources well.

The location of the well is the primary factor in regards to production values. 74 percent of Atlas’ wells are in Greene and Fayette counties, in southwestern Pennsylvania, while 99 percent of Cabot’s wells are in Susquehanna County. Similarly, 79 percent of Range Resources’ wells are in the its southwestern PA stronghold of Washington County, while 62 percent of Chesapeake’s wells are in Bradford county, in the northeast.

Pennsylvania unconventional gas production by county, from July to December 2013.

Table 2: PA unconventional gas production by county, from July to December 2013

Altogether, there are unconventional wells drilled in 38 Pennsylvania counties, 33 of which have wells that are producing (see Table 2). And yet, fully 1 trillion cubic feet (Tcf) of t he 1.7 Tcf produced by unconventional wells during the six month period in Pennsylvania came from the three northeastern counties of Susquehanna, Bradford, and Lycoming.

While production in Greene County does not compare to production in Susquehanna, this disparity still does not account for the really poor production of Atlas wells, as that operator averages less than one fourth of the typical well in the county. Nor can we blame the problem on inactive wells, as 84 of their 85 wells in Greene County are listed as being in production. There is an explanation, however. All of these Atlas wells were drilled from 2006 through early 2010, so none of them are in the peak of their production life cycles.

There is a different story in Allegheny County, which has a surprising high per well yield for a county in the southwestern part of the state. Here, all of the wells on the report were drilled between 2008 and 2013, and are therefore in the most productive part of the well’s life cycle. Only the most recent of these wells is listed as not being in production.

Per well production during the last half of 2013 for unconventional wells in Pennsylvania by year drilled.

Table 3: Per well production during last half of 2013 for PA unconventional wells by spud year

Generally speaking, the further back a well was originally drilled, the less gas it will produce (see Table 3). At first glance, it might be surprising to note that the wells drilled in 2012 produced more gas than those drilled in 2013, however, as the data period is for the last half of 2013, there were a number of wells drilled that year that were not in production for the entire data cycle.

In addition to gas, there were 1,649,699 barrels of condensate and 182,636 barrels of oil produced by unconventional wells in Pennsylvania during the six month period. The vast majority of both of these resources were extracted from Washington County, in the southwestern part of the state. 540 wells reported condensate production, while 12 wells reported oil.

Waste

There are eight types of waste detailed in the Pennsylvania data, including:

Basic Sediment (Barrels) – Impurities that accompany the desired product
Drill Cuttings (Tons) – Broken bits of rock produced during the drilling process
Flowback Fracturing Sand (Tons) – Sand used as proppants during hydraulic fracturing that return to the surface
Fracing Fluid Waste (Barrels) – Fluid pumped into the well for hydraulic fracturing that returns to the surface. This includes chemicals that were added to the well.
Produced Fluid (Barrels) – Naturally occurring brines encountered during drilling that contain various contaminants, which are often toxic or radioactive
Servicing Fluid (Barrels) – Various other fluids used in the drilling process
Spent Lubricant (Barrels) – Oils used in engines as lubricants

Method of disposing of waste generated from unconventional wells in Pennsylvania from July to December 2013.

Table 4: Method of disposing of waste generated from unconventional wells in PA from July to December 2013

Solid and liquid waste disposal for the top 20 producers of unconventional liquid waste in Pennsylvania during the last half of 2013.

Table 5: Solid & liquid waste disposal for top 20 producers of PA unconventional liquid waste during last half of 2013

This table shows solid and liquid waste totals for the ten counties that produced the most liquid waste over the six month period.

Table 6: Solid & liquid waste totals for the 10 counties that produced the most liquid waste over the 6 month period

There are numerous methods for disposing of drilling waste in Pennsylvania (see Table 4). Some of the categories include recycling for future use, others are merely designated as stored temporarily, and others are disposed or treated at a designated facility. One of the bright points of the state’s waste data is that it includes the destination of that waste on a per well basis, which has allowed us to add receiving facilities to the map at the top of the page.

As eight data columns per table is a bit unwieldy, we have aggregated the types by whether they are solid (reported in tons) or liquid (reported in 42 gallon barrels). Because solid waste is produced as a result of the drilling and fracturing phases, it isn’t surprising that the old Atlas wells produced no new solid waste (see Table 5). Chevron Appalachia is more surprising, however, as the company spudded 46 wells in 2013, 12 of which were started during the last half of the year. However, Chevron’s liquid waste totals were significant, so it is possible that some of their solid waste was reported, but miscategorized.

As with production, location matters when it comes to the generation of waste from these wells. But while the largest gas producing counties were led by three counties in the northeast, liquid waste production is most prolific in the southwest (see Table 6).

Table 7: PA unconventional operators with the most wells that produced gas, oil, and/or condensate, but no amount of waste.

Finally, we will take a look at the 359 wells that are indicated as in production, yet were not represented on the waste report as of March 6th. These remarkable wells are run by 38 different operators, but some companies are luckier with the waste-free wells than their rivals. As there was a six-way tie for 10th place among these operators, as sorted by the number or wells that produce gas, condensate, or oil but not waste, we can take a look at the top 15 operators in this category (see Table 7). Of note, gas quantity only includes production from these wells. Column on the right shows total number of wells that are indicated as producing, for that same operator, regardless of waste production.

114 of Southwestern Energy’s 172 producing wells were not represented on the waste report as of March 6th, representing just under two thirds of the total. In terms of the number of waste-free wells, Atlas was second, with 55. As for the highest percentage, Dominon, Hunt, and Texas Keystone all managed to avoid producing any waste at all for each of their seven respective producing wells, according to this self-reported data.

Over 1.1 Million Active Oil and Gas Wells in the US

March 4, 2014/by Matt Kelso, BA

Please Note

Click here to view an update on this topic

Many people ask us how many wells have been hydraulically fractured in the United States. It is an excellent question, but not one that is easily answered; most states don’t release data on well stimulation activities. Also, since the data are released by state regulatory agencies, it is necessary to obtain data from each state that has oil and gas data to even begin the conversation. We’ve finally had a chance to complete that task, and have been able to aggregate the following totals:

Oil and gas summary data of drilled wells in the United States.

While data on hydraulically fractured wells is rarely made available, the slant of the wells are often made accessible. The well types are as follows:

Directional: Directional wells are those where the top and the bottom of the holes do not line up vertically. In some cases, the deviation is fairly slight. These are also known as deviated or slant wells.
Horizontal: Horizontal wells are directional wells, where the well bore makes something of an “L” shape. States may have their own definition for horizontal wells. In Alaska, these wells are defined as those deviating at least 80° from vertical. Currently, operators are able to drill horizontally for several miles.
Directional or Horizontal: These wells are known to be directional, but whether they are classified as horizontal or not could not be determined from the available data. In many cases, the directionality was determined by the presence of directional sidetrack codes in the well’s API number.
Vertical: Wells in which the top hole and bottom hole locations are in alignment. States may have differing tolerances for what constitutes a vertical well, as opposed to directional.
Hydraulically Fractured: As each state releases data differently, it wasn’t always possible to get consistent data. These wells are known to be hydraulically fractured, but the slant of the well is unknown.
Not Fractured: These wells have not been hydraulically fractured, and the slant of the well is unknown.
Unknown: Nothing is known about the slant, stimulation, or target formation of the well in question.
Unknown (Shale Formation): Nothing is known about the slant or stimulation of the wells in question; however, it is known that the target formation is a major shale play. Therefore, it is probable that the well has been hydraulically fractured, with a strong possibility of being drilled horizontally.

Wells that have been hydraulically fractured might appear in any of the eight categories, with the obvious exception of “Not Fractured.” Categories that are very likely to be fractured include, “Horizontal”, “Hydraulically Fractured”, and “Unknown (Shale Formation),” the total of which is about 32,000 wells. However, that number doesn’t include any wells from Texas or Colorado, where we know thousands wells have been drilled into major shale formations, but the data had to be placed into categories that were more vague.

Oil and gas wells in the United States, as of February 2014. Location data were not available for Maryland (n=104), North Carolina (n=2), and Texas (n=303,909). To access the legend and other map tools, click the expanding arrows icon in the top-right corner.

The standard that we attempted to reach for all of the well totals was for wells that have been drilled but have not yet been plugged, which is a broad spectrum of the well’s life-cycle. In some cases, decisions had to be made in terms of which wells to include, due to imperfect metadata.

No location data were available for Maryland, North Carolina, or Texas. The first two have very few wells, and officials in Maryland said that they expect to have the data available within about a month. Texas location data is available for purchase, however such data cannot be redistributed, so it was not included on the map.

It should not be assumed that all of the wells that are shown in the map above the shale plays and shale basin layers are actually drilled into shale. In many cases, however, shale is considered a source rock, where hydrocarbons are developed, before the oil and gas products migrate upward into shallower, more conventional formations.

The raw data oil and gas data is available for download on our site in shapefile format.

Oil Drilling’s Impact on ND Communities

February 7, 2014/by Guest Author

By Thomas DiPaolo, 2013 GIS Intern, FracTracker Alliance

ND Shale Viewer

Out of North Dakota’s 53 counties, 19 are responsible for producing the oil and natural gas that has brought the state so much prosperity and attention. It’s the latest get-rich-quick scheme, and one that works better than that name would suggest: drive to North Dakota, work in the oil fields for six months, and go home with enough money to find something more permanent. This means that some of the quiet towns overlying the Bakken formation are exploding in size, and many of their new residents lack any connection to these communities when they’re off duty. In the past, similar population booms have been tied to a corresponding increase in crime rates and drug usage, and FracTracker Alliance has examined the available data to find out how much life has changed in North Dakota since the oil started to flow.

Housing Availability

There’s a reason why the you have to drive to North Dakota if you want to stay in the black, and it helps if you’ve got a comfortable car.

Perhaps the biggest problem here, perhaps a cause of others, is that there is simply not enough housing for everyone who wants to work in North Dakota. Trailer parks pack every available inch of space for families from out of state prepared to settle in, becoming themselves towns in miniature, and one of the benefits to consider when working for one oil drilling company over another is to find out which ones are constructing dedicated worker housing and amenities. Familiarity doesn’t fail to breed contempt; demand for living space is so high, in fact, that families who have lived in these towns their whole lives are being forced out as rent prices rise without end. Meanwhile, many have taken to simply sleeping in their cars, and tensions have grown as stores forbid them from parking overnight in their lots.

Crime

With the number of people moving into the state to work in the oil fields, or in industries that support them, North Dakota’s population reached 699,628 in 2012, a jump from the 642,200 people of 2000. More people, of course, means greater effort required to keep the peace – The number of law enforcement officers accordingly jumped from 967 in 2000 to 1,253 in 2012. At first glance, one might think that did the job, since the crime rate fell from 2,203 index crimes¹ reported per 100,000 people to 2,122 per 100,000 people, and the number of arrests per officer stayed constant (3.1 in 2000, 3.0 in 2012). That conclusion doesn’t hold up well when you look at how crime has fluctuated within the oil-producing counties.² The population there has risen to 183,940 people, from just 167,515 people in 2000, and it currently employs 379 law enforcement officers, up from 250 officers. In 2000 the crime rate was already in excess of the state average at 1,582 index crimes reported per 100,000 people and 8.3 arrests per law enforcement officer. By 2012, those figures reached 1,629 crimes per 100,000 people and 12.8 arrests per officer. With only a quarter of the state’s population, the crime rate is three-quarters of the state average. This upswell applies especially to violent crimes. Violent crime reports, numbered at 558 statewide in 2000, nearly tripled to 1,445 in 2012; in the oil counties, they more than tripled from 103 to 363 crimes reported. That number carries through in the crime rate figures; statewide, 206.5 violent crimes occurred per 100,000 people in 2012, while only 86.9 crimes were reported per 100,000 people in 2000; in the oil counties, 197.3 violent crimes were reported per 100,000 people in 2012, compared to only 61.5 violent crimes per 100,000 people in 2000. See Table 1 for a comparison of total and violent crimes between the year 2000 and the year 2012.

Table 1. Crime rates per 100,000 people in North Dakota (2000 vs. 2012)

	Total Index Crimes		Violent Crimes
	Statewide	Oil Counties	Statewide	Oil Counties
2000	2,203	1,582	86.9	61.5
2012	2,122	1,629	206.5	197.3

Where the line blurs is in addressing property crime. Until 2009, there had been a steady decline in the rate of property crime. Since then, however, it has been increasing every year, even if the 2012 figures are still beneath those of 2000. Statewide, the number of property crimes hovered at 13,592 reported crimes in 2000 and 13,402 in 2012, while in the oil counties they rose slightly from 2,547 property crimes in 2000 to 2,634 crimes in 2012. At the same time, the property crime rates fell both statewide (2,116 crimes per 100,000 people to 1,916 per 100,000 people) and in the oil counties (1,529 crimes per 100,000 people to 1,486 per 1000,000 people).

Prostitution

When you have that many single young men together, as so many of the oil field workers are, a market inevitably springs up for very particular crimes. Prostitution stings consume a greater quantity of police time than ever before, with some ND counties reporting their first prostitution arrests ever. In many cases, the suspects in these cases demonstrate a similar attitude to the oil workers they court: stay for a brief period (typically days rather than months), make enough money to support themselves, and keep going out of town. Officers often say that these cases are risky, as they require enough evidence to prove the intent of both parties to exchange money for sex. Without an undercover officer to carry out a sting, many cases could be accused of discrimination, especially in cases where race may be an issue. In other situations, sting operations have provided evidence of drug activity in addition to prostitution.

Drug Use

Juvenile Alcohol Use

In addition to the oil boom, North Dakota has the uncomfortable claim of being one of the nation’s leaders when it comes to binge drinking. It’s notable then to see that, while juvenile³ alcohol use has fallen drastically across the board, juveniles are developing more permissive attitudes towards alcohol use. Between 2000 and 2011, the number of juveniles who reported using alcohol within the previous month fell from 18,000 to 7,000, and it fell from 11,000 to 4,000 juveniles in regards to binge drinking⁴ on a weekly basis. At the same time, the number of juveniles showing signs of alcohol dependence or abuse fell from 6,000 to 2,000, and those described as needing but not receiving treatment for alcohol abuse fell from 5,000 to 2,000. Yet only 17,000 juveniles reported perceiving great risk from said binge drinking in 2011, where 22,000 had reported perceiving great risk in 2000. Why are more juveniles rejecting personal alcohol use while becoming less concerned with others’ usage?

Adult Drug & Alcohol Use

Whatever the reason, adult alcohol usage has demonstrated the opposite trend: more people are drinking but fewer enjoy it. Between 2000 and 2011, the number of adults using alcohol monthly rose from 286,000 to 320,000, and those binge drinking weekly rose from 144,000 to 165,000. The number of adults perceiving great risk from weekly binge drinking also rose from 173,000 to 183,000, but the number with signs of alcohol dependence or abuse rose from 33,000 to 47,000. Interestingly, the number of adults described as needing but not receiving treatment for alcohol use has barely changed in this time; 46,000 adults were characterized this way in 2000, as opposed to 45,000 of them in 2011.

Smoking and Marijuana Use

The one trend shared between both juveniles and adults is a steady increase in the number of people expressing permissive attitudes towards the use of marijuana. In 2000, 4,000 juveniles and 13,000 adults reported using marijuana within the previous month; by 2011, only 2,000 juveniles reported using marijuana within the previous month, but the number of adults doing so had jumped to 23,000. At that time, only 17,000 juveniles and 171,000 adults reported perceiving great risk from the use of marijuana on a monthly basis, down from 25,000 and 213,000 respectively in 2000. These figures come at a time when other forms of smoking are becoming less popular across the U.S. In 2000 in ND, 16,000 juveniles were using tobacco products on a monthly basis, and 13,000 were using cigarettes specifically; those numbers had fallen to 6,000 and 5,000 juveniles respectively by 2000. Even among adults there were small declines over this time period: 154,000 adults were using tobacco monthly in 2011 as opposed to 161,000 in 2000, and 121,000 adults as opposed to 128,000 were using cigarettes. And while the number of juveniles perceiving great risk from pack-a-day smoking fell from 38,000 to 32,000 between 2000 and 2011, while 346,000 adults perceived great risk from it in 2011, as opposed to 315,000 in 2000.

Footnotes

According to the Crime and Homicide Reports of the North Dakota Attorney General’s office, index crimes are reported to the National Uniform Crime Reporting program managed by the Federal Bureau of Investigation in order to broadly describe the level of criminal activity around the country. They are divided into two categories, violent and property-related. The violent index crimes tracked by North Dakota are murder and non-negligent manslaughter, forcible rape, robbery, and aggravated assault. The property index crimes tracked by the state are burglary, larceny and theft, and motor vehicle theft.
The North Dakota Association of Oil and Gas Producing Counties lists the following counties as its members: Adams, Billings, Bottineau, Bowman, Burke, Divide, Dunn, Golden Valley, Hettinger, McHenry, McKenzie, McLean, Mercer, Mountrail, Renville, Slope, Stark, Ward, and Williams.
The National Surveys on Drug Use and Health define a “juvenile” as any person between the ages of 12 and 17 years, and an adult as any person aged 18 years or older.
The National Surveys on Drug Use and Health define “binge drinking” as consuming five or more alcoholic beverages in one sitting.

Ohio Production and Injection Well Firms Map

February 6, 2014/by Ted Auch, PhD

Our latest Ohio-focused map shows the many companies involved in directional drilling in the state and the contact information for these firms.

Layer Descriptions

1. UNIVERSAL WELL SERVICES

Universal Well Services Inc. is a major firm involved in all manner of directional drilling services with an office in Wooster, OH, one in Allen, KY, six in Pennsylvania, six in Texas, and one in West Virginia

2. LLC & MLP’s

This is an inventory of 410 Ohio directional drilling affiliated LLC and MLP firms and contact information. Seventy-eight percent of these firms are domiciled in Ohio. The other primary states that house these firms are Pennsylvania (22), Texas (23), and West Virginia (9). The Economist wrote of these types of firms:

The move away from the C corporation began in earnest in 1975. Wyoming, that vibrant business hub, adopted a new entity structure, the limited-liability company (LLC). Imported from Panama, it provided the tax treatment of a partnership while preserving the corporate protection from individual liability for company debts and litigation. Other states followed in adopting the model. Businesses were quick to see the advantages. The various new types of firm that have risen in the wake of the LLC… make similar use of partnership structures. They have tended to be industry- or sector-specific, at least to begin with. The energy business has a lot of MLPs not only because it needs capital but because it is an easy place to set them up: since 1987, tax law has allowed “mineral or natural resource” companies to operate as listed partnerships, while withholding that privilege from others. But as with other pass-through structures, the constraints are being lowered and circumvented.

3. DRILLING FIRMS

This is an inventory of 393 Ohio Department of Natural Resources permitted directional and injection drilling firms with single locations and their contact information. Seventy-six percent of these firms are domiciled in Ohio with the other primary states of incorporation being Pennsylvania (15), Texas (14), Michigan (11), and West Virginia (9). Only 3 of these firms listed in the Ohio RBDMS Microsoft Access Database contained correct contact information or addresses. According to ODNR staff – and primary FOIA contact:

… it looks like the [active drillers] list [doesn’t contain] much information on the companies in general…We have mailing information for the operating companies, but a lot of the time they subcontract out to get their drillers. We do not require the information of the drillers they contract.

4. ADDITIONAL DRILLERS

This is an inventory of the 40 known locations for six firms permitted to drill in Ohio. The same lack of contact and address data for these firms were true for this data. The primary firms are Butch’s Rathole and Nomac Drilling Corporation. Given that the ODNR RBDMS does not indicate the actual location from which these companies migrated into the Ohio shale industry we decided to include all known locations for these firms.

5. CANADIAN FIRMS

This is an inventory of the 14 known locations for the 5 Canadian drilling firms permitted in Ohio. The primary firm is Savannah Drilling, which is composed of 10 locations across Alberta and Saskatchewan.

6. AMERICAN SUPPORTING CO.

This is an inventory of 1,837 Ohio energy firms operating in the Utica and Marcellus shale or servicing it in a secondary or tertiary fashion. Seventy-five percent (1,386) of these firms are domiciled in Ohio with secondary hotspots in Texas (76), West Virginia (65), Pennsylvania (49), Michigan (34), Colorado (27), Illinois (22), Oklahoma (21), California (16), New York and New Jersey (27), Kentucky (14).

7. ADDITIONAL SUPPORTING CO.

This shows an inventory of 10 Ohio energy firms operating in the Utica and Marcellus shale or servicing it in a secondary or tertiary fashion extracted from the ODNR RBDMS that did not contain locational or contact information.

8. CANADIAN SUPPORTING CO.

This is an inventory of 5 (1 company Mar Oil Company was not found) Canadian energy firms operating in the Utica and Marcellus shale or servicing it in a secondary or tertiary fashion.

9. BRINE HAULERS

This is an inventory of 505 ODNR permitted brine haulers active in the transport and disposal of hydraulic fracturing waste either via injection or waste landfill disposal. Seventy-six percent of these firms are domiciled in Ohio with the primary cities being Zanesville (18), Cambridge, Wooster, and Millersburg (12 each), Canton and Marietta (11 each), Columbus (9), Jefferson (9), Logan (8), and North Canton and Newark (7 each). Pennsylvania and West Virginia are home to 84 and 32 brine haulers, respectively.

Mapping California’s State Bill 4 (SB4) Well Stimulation Notices

January 31, 2014/by Kyle Ferrar, MPH

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

Introduction

California passed State Bill 4 (SB4) in September, 2013 to develop and establish a regulatory structure for unconventional resource extraction (hydraulic fracturing, acidizing, and other stimulation techniques) for the state. As a feature of the current version of the regulations, oil and gas drilling/development operators are required to notify the California Department of Conservation’s Division of Oil Gas and Geothermal Resources (DOGGR), as well as neighboring property owners, 30 days prior to stimulating an oil or gas well. In addition to property owners having the right to request baseline water sampling within the the following 20 days, DOGGR posts the well stimulation notices to their website.

Current State of Oil and Gas Production

The DOGGR dataset of well stimulation notices was downloaded, mapped, the dataset explored, and well-site proximity to certain sites of interest were evaluated using GIS techniques. First, the newest set of well stimulation notices, posted 1/17/14 were compared to a previous version of the same dataset, downloaded 12/27/13. When the two datasets are compared there are several distinct differences. The new dataset has an additional field identifying the date of permit approval and fields for latitude/longitude coordinates. This is an improvement, but there is much more data collected in the DOGGR stimulation notification forms that can be provided digitally in the dataset, including sources of water, amount of water used for stimulation, disposal methods, etc… An additional 60 wells have been added to the dataset, making the total count now 249 stimulation notices, with 37 stimulated by acid matrix (acidizing), 212 hydraulically fractured, and 3 by both. Of the 249, 59 look to be new wells as the API identifcation numbers are not listed in the DOGGR “AllWells.zip” database here, while 187 are reworks of existing wells. A difference of particular interest is the discrepancy in latitudes and longitudes listed for several well-sites. The largest discrepancy shows a difference of almost 10,000 feet for an Aera Energy well (API 3051341) approved for stimulation December 23, 2013. The majority of the well stimulations (246/249) are located in Kern County, and the remaining three are located in Ventura County.

Figure 1. Stimulation Notices and Past/Present Oil and Gas Wells
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

Well Spacing

As can be seen in Figure 1, the well stimulations are planned for heavily developed oil and gas fields where hydraulic fracturing has been used by operators in the past. California is the 4th largest oil producing state in the nation, which means a high density of oil and gas wells. Many other states limit the amount of wells drilled in a set amount of space in support of safer development and extraction. In Ohio, unconventional wells (>4,000 foot depths) have a 1,000 foot spacing requirement , West Virginia has a 3,000 foot requirement for deep wells , and the Texas Railroad Commission has set a 1,200 foot well spacing requirement. Using Texas’s setback as an example buffer for analysis, 241/249 of the DOGGR new stimulations are within 1,200 feet of an active oil and gas well. Of the 364 hydraulically fractured oil and gas wells DOGGR has listed as “New” (they are not yet producing, but are permitted and may be in development), 351 are within 1,200 feet of a well identified in DOGGR’s database as an active oil and gas well. One of the industry promoted benefits of using stimulations such as hydraulic fracturing is the ability to decrease the number of well-sites necessary to extract resources and therefore decrease the surface impact of wells. This does not look to be the practice in California.

Environmental Media

Following this initial review of oil and gas production/development, three additional maps were created to visualize the environmental media threatened by contamination events such as fugitive emissions, spills or well-casing failures. The maps are focused on themes of freshwater resources, ambient air quality, and conservation areas.

Freshwater Resources

Figure 2. New Wells, Stimulation Notices and California’s Freshwater Resources
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

Freshwater resources are limited in arid regions of California, and the state is currently suffering from the worst drought on record. In light of these issues, the FracMapper map “New Well Stimulations and California Freshwater Resources” includes map layers focused on groundwater withdrawals, groundwater availability, Class II wastewater injection wells, watershed basins, and the United States Geological Survey’s (USGS) National Hydrography Data-set (NHD). Since California does not have a buffer rule for streams and waterways, we used the setback regulation from Pennsylvania for an analysis of the proximity of the well stimulation notices to streams and rivers. In Pennsylvania, 300 feet is the minimum setback allowed for hydraulic fracturing near recognized surface waters. Of the 246 wells listed for new stimulation, 26 are within 300 feet of a waterway identified in the USGS’s NHD. The watersheds layer shows the drainage areas for these well locations. As a side note, the state of Colorado does not allow well-sites located within 100 year flood plains after the flash floods in September 2013 that caused over 890 barrels of oil condensates to be spilled into waterways. Also featured in Figure 2 are the predominant shallow aquifers in California. The current well stimulations posted by DOGGR are located in the Elk Hills (Occidental Inc.), Lost Hills (Chevron), Belridge and Ventura (both Aera Production) oil fields and have all exempted out of a groundwater monitoring plans based on aquifer exemptions, even though the aquifers are a source of irrigation for the neighboring agriculture. Stimulation notices by Vintage Production in the Rose oil field, located in crop fields on farms, are accompanied by a groundwater and surface water monitoring plan. Take notice of the source water wells on the map that provide freshwater for both the acidizing and hydraulic fracturing operations and the Class II oil and gas wastewater injection wells that dispose of the produced waters. Produced wastewaters may also be injected into Class II enhanced oil recovery water flood wells, and several of the stimulation notices have indicated the use of produced waters for hydraulic fracturing.

Ambient Air Quality

Figure 3. California New Wells, Stimulation Notices and Air Quality
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

Impacts to ambient air quality resulting from oil and gas fields employing stimulation techniques have been documented in areas like Wyoming’s Upper Green River Basin , the Uintah Basin of Utah , and the city of Dish, Texas . Typically, ozone is considered a summertime issue in urban environments, but the biggest threat to air quality in these regions has been elevated concentrations of ozone, particularly in the winter time. Ozone levels in these regions have been measured at concentrations higher than would typically be seen in Los Angeles or New York City. In Figure 3, the state and federal ozone attainment layers show that the areas with the highest concentrations of “new” wells and the DOGGR New Stimulation Notices do not pass ambient air criteria standards to qualify as “attainment” status for either state or federal ambient ozone compliance, meaning their ambient concentrations reach levels above health standards. Other air pollutants known to be released during oil and gas development, stimulation, and production include volatile organic compounds (VOCs) such as Benzene, Toluene, Ethylbenzene and xylene (BTEX); carbon monoxide (CO); hydrogen sulfide (H2S), Nitrogen Oxides (NOx), and sulfur dioxide (SO2), and methane (CH4), a potent greenhouse gas. It is important to point out that ground level ozone is not emitted directly but rather is created by chemical reactions between NOx and VOCs. Besides ozone, all these other air pollutants are in “attainment” in California except NOx in Los Angeles County. There have not been any stimulation notices posted in Los Angeles County, but the South Coast Air Quality Monitoring District identifies 662 recent wells that have been stimulated using hydraulic fracturing, acidizing, or gravel packing. See the Local Actions map of California for these well sites.

Conservation Areas

Figure 4. New Wells, Stimulation Notices and Conservation Areas
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

The map in Figure 4, “New Well Stimulations and Conservation Lands”, features land use planning maps developed by California and Federal agencies for conservation of the environment for multiple uses, ranging from recreation to farming and agriculture. Many of the Stimulation Notices as well as “new” well sites located in Kern County are located in or along the boundary of the San Joaquin Valley Conservation Opportunity; land identified by the California Department of Fish and Game, Parks and Recreations, and Transportation (Caltrans) as important for wildlife connectivity. Oil and gas development inevitably results in loss of habitat for native species. Habitat disturbance and fragmentation of the natural ecosystems can pose risks particularly for endangered species like the San Joaquin Kit Fox, California Condor, and the blunt-nosed leopard lizards.

The California Rangeland Priority Conservation Areas layer was created to identify the most important areas for priority efforts to conserve the Oak Savannah grasslands of high diversity that host many grassland birds, native plants, and threatened vernal pool species. The areas of high biodiversity value are marked in red as “critical conservation areas”. The majority of the new well stimulations are encroaching on the borders of these “critical areas,” particularly in the Belridge oil field. The CA Farmland Mapping and Monitoring Program map layer rates land according to soil quality to analyze impacts on California’s agricultural resources. The majority of new stimulations and new oil wells are located on the border of areas designated as “prime farmland,” particularly the Belridge and Lost Hills fields. The Rose field on the other hand is located within the “prime farmland” and “farmland of statewide importance.” Also, well-sites from all fields in Kern County are located on Williamson Act Agricultural Preserve Land Parcels. By enrolling in the program these areas can take advantage of reduced tax rates as they are important buffers to reduce urban sprawl and over-development. Although the point of the act was to protect California’s important farmland and agriculture, some parcels enrolled in the Williamson Agricultural Preserve Act program even house stimulation notice sites and “new” hydraulically fractured wells.

Discussion

While allowing hydraulic fracturing, acidizing and other stimulations until January 1, 2015 under temporary regulations, SB4 requires the state of California to complete an Environmental Impact Review (EIR). New regulations will then be developed on the recommendations of the EIR. The regulations will be enforced by the Division of Oil, Gas, and Geothermal Resources (DOGGR), the agency currently responsible for issuing drilling permits to operators in the state. In some municipalities of California, an additional “land-use” development permit is required from the local land-use agency (Air district, Water District, County, other local municipality or any combination) for an operator to be granted permission to drill a well. In most areas of California a “land-use” permit is not required, and only the state permit from DOGGR is necessary. A simple explanation is DOGGR grants the permit for everything that occurs underground, and in some locations a separate regulatory body approves the permit for what occurs above the ground at the surface. The exceptions are San Benito County which has a 500 foot setback from roads and buildings, Santa Cruz County, which passed a moratorium, Santa Barbara with a de facto ban*, and the South Coast Air quality Monitoring District’s notification requirements, permitting a well stimulation (such as “fracking” or “acidizing”). For the rest of the state permitting a well stimulation is essentially the same as permitting a conventional well-site, although it should be recognized that some counties like Ventura have setback and buffer provisions for all (conventional and unconventional) oil and gas wells. Additionally, DOGGR’s provisional regulations do require chemical disclosures to FracFocus and public notifications to local residents 30 days in advance, but lacks public health and safety provisions such as setbacks, continuous air monitoring, and the majority of wells in the notices are exempt from groundwater monitoring, While public notifications and chemical disclosures are all important for liability and tracking purposes, they are no substitute for environmental and engineering standards of practice including setbacks and other primary protection regulations to prevent environmental contamination. The state-sponsored EIR is intended to inform these types of rules, but that leaves a year of development without these protections.
*Santa Barbara County requires all operators using hydraulic fracturing to obtain an oil drilling production plan from the Santa Barbara County Planning Commission. No operator has applied for a permit since the rule’s passing in 2011.

References

DOGGR. 2014. Welcome to the Division of Oil, Gas and Geothermal Resources. Accessed 1/28/14.
Lawriter Ohio Laws and Rules. 2010. 1501:9-1-04 Spacing of wells. Accessed 1/29/14.
WVDNR. 2013. Regulations. Accessed 1/29/14.
Railroad Commission of Texas. 2013. Texas Administrative Code. Accessed 1/28/14.
PADEP. 2013. Act 13 Frequently Asked Questions. Accessed 1/29/14.
U.S.EPA. 2008. Wyoming Area Designations for the 2008 Ozone National Ambient Air Quality Standards. Accessed 1/29/14.
UT DEQ. 2014. Uintah Basin. Accessed 1/29/14.
UT DEQ. 2012. 2012 Uintah Basin Winter Ozone & Air Quality Study.
Wolf Eagle Environmental. 2009. Town of Dish, TX Ambient Air Monitoring Analysis.

Ohio Hydrocarbon Production Well Inspections and Violations

January 27, 2014/by Ted Auch, PhD

Inspections and Violations in Ohio

Only a few states in the U.S. currently release free violations data related to unconventional oil and gas drilling. The Ohio Department of Natural Resources (ODNR) maintains an inventory of well inspections and violations within its RBDMS database. We examined and mapped their data with a focus on hydrocarbon (oil and natural gas) production wells and relevant Class II Injection¹ wells – where the high volumes of liquid wastes produced during hydrocarbon extraction are often disposed of, deep within the earth.

By the Numbers

As of January 2013 there were a total of 5,954 hydrocarbon well inspections and 956 “True” violations. “True” violations refer to those inspections that were deemed to be in violation of the Ohio Revised Code (OAC) Chapter 1501:9-3 Saltwater Operation or Chapter 1501:9-1 Oil Well Drilling. Violations and/or inspections tend to fall under a couple of categories including compliance notices, neighbor phone call, or routine field visits or inspections. There have been 470 and 430 “Complaint” and “Request” based inspections to date, respectively (Table 1).

This graph depicts monthly and cumulative Ohio hydrocarbon production well inspections and ODNR deemed "True" violations between September 2010 and January 2013.

Figure 1. Cumulative OH hydrocarbon production well inspections & ODNR determined true violations (Sept 2010 – Jan 2013)

The ratio of inspections to violations issued over time in Ohio has been somewhat variable, but a trend does seem to be slowly emerging. At the present time average hydrocarbon well inspections are increasing by 7 per month, while true violations are only increasing by 0.5 per month (Figure 1)². Thus, the ratio of inspections-to-violations declined from its September 2010 high of 13.2 to 3.1 in February 2011. This ratio, however, began to rise shortly thereafter.

Assuming the current trajectory holds, the next ODNR RBDMS update should report approximately 11,696 inspections as of the end of January 2014 and more than 48,000 total inspections by January 2018. This trajectory dictates that we will see roughly 1,500-1,600 true violations by January 2014 and approximately 4,500 by January 2018.

Map Description

The map below displays a monthly updated inventory of Ohio’s hydrocarbon and relevant injection well-related violations. This map will be updated monthly around the 25th of each month. We have established fixed search criteria for the RBDMS Microsoft Access database, which is updated weekly. Inspection purposes include general complaints, civil action, compliance agreement, and criminal actions, while there are myriad inspection descriptions (Table 2).

To view the legend, metadata, and map fullscreen click on the arrows in the top right hand corner of the map.

Inspection Data Availability and Analysis

Significant data gaps exist with respect to latitude-longitude across Ohio’s current inventory of Class II and hydrocarbon well inspections (Note: Data is only available up to February 2013). Below we have analyzed the current gap between “Total” inspections and those “w/Latitude-Longitude” data. We are currently working to close these gaps. The largest gap exists for the “Salt Water Injection Wells All Time” (i.e., Hydraulic Fracturing Waste Class II’s) data with only 3.5% of all inspections accompanied by latitude-longitude coordinates.

Production Wells

Pre 9/1/2010 (i.e., First Ohio Utica Permits)
- Total: 63,707
- w/Latitude-Longitude: 24,912
- 39% coverage
Post 9/1/2010 (i.e., First Ohio Utica Permits)
- Total: 13,735
- w/Latitude-Longitude: 5,917
- 43% coverage

Salt Water Injection Wells All Time

Total: 11,939
w/Latitude-Longitude: 413
3.5% coverage

Annular Disposal + Enhanced Oil Recovery + Orphan + Solution Mining Project + Storage Well

Total: 15,694
w/Latitude-Longitude: 5,300
33.8% coverage

Tables

The primary columns of importance to the public in the tables below are “Inspection Purpose”, “Inspection Description”, and “Notification Type.” Eighty-three percent (83%) of the state’s production well inspections were for what seem to be routine “Status Checks.” With respect to notification type, most were categorized as “Unknown” (Tables 1 and 3).

Table 1. Ohio production and Class II injection well Inspection Purposes

Code	Definition	Number of Inspections
C	Complaint	470
CAF	Civil Action Follow-up	4
CMF	Compliance Agreement Follow-up	4
NMF	Notice of Material or Substantial Follow-Up	2
NVF	Notice of Violation Follow-Up	99
OF	Order Follow-Up	4
R	Request	430
SC	Status Check	4,802
—	Unknown	3

Table 2. Ohio production and Class II injection well inspection descriptions

Description

Failure to maintain record of pipeline location

Inadequate pipeline strength

Failure to properly bury pipeline

Well operation causing pollution and contamination

General Safety

Well insufficiently equipped to prevent escape of oil and gas

Failure to legibly identify well

Violation of tank spacing requirements

Violation of tank fire heater spacing requirements

Unattended portable heater less than 50 feet from tank

Violation of separator spacing requirements

Operating tank heater while oil is being produced

Improperly located oil tank

Equipment pressure rated below operating pressure

No SPCC dike/or failure to keep dike free of water or oil

Unlawful venting or flaring of gas

Failure to have required locks, bull plugs

Well incapable of production

Illegal/Unauthorized annular disposal of brine

Unlawful method of storage or disposal of brine

Dike or pit not able to prevent brine escape

Unlawful use of pit for temporary brine storage

Use of pit of dike for ultimate disposal of brine

Disposal of muds or cuttings in violation of a rule

Failure to keep dike or pit free of brine / other wastes

Illegal/Unauthorized annular disposal of brine

Non registered operator/ Bond/ Insurance

Table 3. Ohio production and Class II injection well notification types

Code	Definition	Number of Inspections
CN	Compliance Notice	470
FVI	Field Visit or Inspection	225
LET	Informal Letter	2
NOV	Notice of Violation	74
OTH	Other Notification	8
PHN	Phone Call	225
—	Unknown	4,810

Endnotes

1. Relevant Class II wells include Salt Water Injection, Annular Disposal, Enhanced Oil Recovery, Orphan, Solution Mining Projects, and Storage Wells

2. If we remove the first month of 2013, the former increases to 9 per month and the latter 0.8 per month.

Louisiana Shale Viewer Added to FracMapper

January 15, 2014/by Matt Kelso, BA

Louisiana is the 21st state to have its own shale viewer map on the FracMapper section of our website:

Louisiana Shale Viewer. Please click expanding arrows icon in upper-right corner of the map to access additional details, including the legend.

In addition to production wells and salt water disposal wells, which are available in most states, Louisiana also has some data that is relatively rare, including pits, storage wells, and inspections. In addition, most of these datasets contain additional information that can be accessed by links in the popup boxes. Due to the large number of features on the map, users will need to zoom in several clicks, to the point where the “generalized” layers are replaced with the actual data layers.