Compilation of Publicly Available Sources of Voluntary Management Practices 

for Oil and Gas Exploration & Production (E&P) Wastes

As They Address Pits, Tanks, and Land Application

US Environmental Protection Agency

Office of Solid Waste and Emergency Response

Office of Resource Conservation and Recovery

April 1, 2014 
April 1, 2014 Page 2

Disclaimer:

This document does not represent and should not be construed to represent any Agency determination, policy, or 

regulation. This document may not be relied on to create any rights, substantive or procedural, enforceable by any 

party in litigation with the United States. Inclusion of documents in this report does not constitute a US EPA 

endorsement of their contents, only an acknowledgment that these documents exist and describe voluntary 

management practices for oil and gas exploration and production (E&P) wastes as they address pits, tanks, and 

land application. . The use of the phrase “Best Management Practices” throughout this document is not intended 

to suggest that EPA has concluded that these particular practices are in fact “best management practices” or that 

adoption of these practices will protect human health and the environment. Mention of trade names or commercial 

products does not constitute endorsement or recommendation for use.
April 1, 2014 Page 3

Table of Contents

Executive Summary........................................................................................................................................................................................................ 4

1. Introduction and Purpose of Review ..................................................................................................................................................................... 6

2. Methodology.......................................................................................................................................................................................................... 8

3. Sources of Voluntary Management Practices for Oil & Gas E&P Wastes.............................................................................................................. 9

4. Selected Sources of Voluntary Management Practices for Oil & Gas E&P Wastes............................................................................................. 19

5. Summary of Selected Voluntary Management Practices for Oil and Gas E&P Wastes as They Address Pits, Tanks, and Land Application...... 24

6. Findings................................................................................................................................................................................................................ 97
April 1, 2014 Page 4

Executive Summary

The Office of Resource Conservation and Recovery (ORCR) conducted a literature review/internet search of voluntary management 

practices for oil and gas exploration and production (E&P) wastes. This review did not include state regulations, which are addressed 

in a separate document titled “Review of State Oil and Natural Gas Exploration, Development, and Production (E&P) Solid Waste

Management Regulations,” or federal regulations, such as the Spill Prevention, Control, and Countermeasure rules. Rather, the focus 

of the review was on such voluntary practices as they address pits, tanks, and land application/disposal. Based on the results of the 

review, EPA agrees with the recommendation of the Shale Gas Production Subcommittee of the Secretary of Energy Advisory Board 

(SEAB) that the federal government should encourage the development of additional and improved “best practices.” It should be 

noted that these voluntary management practices are typically referred to (by the organizations that develop them or those that use 

them) as “Best Management Practices” or “BMPs.” However, in this document the use of the phrase “best management practices” is 

limited to the where the documents themselves use these terms, or otherwise where EPA is quoting another source, and is not intended 

to connote EPA approval of particular practices, nor any determination that such practices will protect human health and the 

environment. 

The SEAB Shale Gas Production Subcommittee defines “best practices” as “improvements in techniques and methods that rely on 

measurement and field experience.”1

 The Subcommittee favors a national approach including regional mechanisms that recognize 

differences in geology, land use, water resources, and regulation.2 The Bureau of Land Management (BLM) of the U.S. Department 

of the Interior defines Best Management Practices (BMPs) as “state-of-the-art mitigation measures applied to oil and natural gas 

drilling and production to help ensure that energy development is conducted in an environmentally responsible manner.” BLM also 

states that, “BMPs should be matched and adapted to meet the site-specific requirements of the project and local 

environment.”3

In August, 2012, ORCR conducted a literature review/internet search and developed a list of over 80 publicly available sources of 

voluntary management practices for oil and gas E&P wastes as they relate to pits, tanks, and land application/disposal. From this list, 

ORCR focused on 14 key sources that are currently widely used and developed summaries of the pit, tank, and land applicationrelated voluntary management practices contained in the 14 selected sources. It is important to note that EPA did not evaluate the 

 1 U.S. DOE, Secretary of Energy Advisory Board, Shale Gas Production Subcommittee Second Ninety Day Report, November 18, 2011, 

http://www.shalegas.energy.gov/resources/111811_final_report.pdf

2 U.S. DOE, Secretary of Energy Advisory Board, Shale Gas Production Subcommittee 90-Day Report, August 18, 2011, 

http://www.shalegas.energy.gov/resources/081811_90_day_report_final.pdf

3 U.S. DOI Bureau of Land Management, BMPs website, http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html
April 1, 2014 Page 5

adequacy or protectiveness of any of the voluntary management practices summarized in this document. Rather, the point of the 

review was to determine the range of voluntary management practices that are currently available, the extent to which such practices 

cover a broad cross-section of geographic conditions, and the source of such management practices.

Based on the review of existing voluntary management practices, ORCR determined that there is much existing guidance developed 

and being used by industry, federal, state, and non-governmental organizations. The scope ranges from local to state, regional, 

national, and international. The guidance documents/websites compiled in this review are readily available to the public. In addition, 

there are ongoing efforts by the various stakeholder groups to continuously develop additional guidances and improve existing ones. 

The literature search is current as of April 1, 2014. The website addresses are current as of April 1, 2014, but are subject to 

change.
April 1, 2014 Page 6

1. Introduction and Purpose of Review

The Office of Resource Conservation and Recovery (ORCR) conducted a literature review/internet search of voluntary management 

practices (also referred to in industry as “Best Management Practices,” or “BMPs”) for oil and gas exploration and production (E&P) 

wastes. The focus of the review was on such voluntary management practices as they address pits, tanks, and land 

application/disposal. This review did not include state regulations, which are addressed in a separate document titled “Review of 

State Oil and Natural Gas Exploration, Development, and Production (E&P) Solid Waste Management Regulations,” or federal 

regulations, such as the Spill Prevention, Control, and Countermeasures rules. Based on the results of the review, EPA agrees with the 

recommendation of the Shale Gas Production Subcommittee of the Secretary of Energy Advisory Board (SEAB) that the federal 

government should encourage the development of additional and improved “best practices.”

The SEAB Shale Gas Production Subcommittee defines “best practices” as “improvements in techniques and methods that rely on 

measurement and field experience.”4

 The Subcommittee favors a national approach including regional mechanisms that recognize 

differences in geology, land use, water resources, and regulation.5 The Bureau of Land Management (BLM) of the U.S. Department 

of the Interior defines BMPs as “state-of-the-art mitigation measures applied to oil and natural gas drilling and production to help 

ensure that energy development is conducted in an environmentally responsible manner.” BLM also states that, “BMPs should be 

matched and adapted to meet the site-specific requirements of the project and local environment.”6

This report contains six sections covering the (1) introduction; (2) methodology; (3) a list of publicly available sources of voluntary 

management practices for oil and gas E&P wastes as they relate to pits, tanks, and land application/disposal; (4) a list of selected 

guidance documents or websites for further analysis; (5) summaries of the relevant practices in the selected guidances; and (6) our 

findings. It is important to note that EPA did not evaluate the adequacy or protectiveness of any of the voluntary management 

practices summarized in this document. Rather, the purpose of the review was to determine the range of voluntary management 

 4 U.S. DOE, Secretary of Energy Advisory Board, Shale Gas Production Subcommittee Second Ninety Day Report, November 18, 2011, 

http://www.shalegas.energy.gov/resources/111811_final_report.pdf

5 U.S. DOE, Secretary of Energy Advisory Board, Shale Gas Production Subcommittee 90-Day Report, August 18, 2011, 

http://www.shalegas.energy.gov/resources/081811_90_day_report_final.pdf

6 U.S. DOI Bureau of Land Management, BMP website, http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html
April 1, 2014 Page 7

practices that are currently available, the extent to which such practices cover a broad cross-section of geographic conditions; and the 

source of such practices.

The summaries in Section 5 contain the following information for each document: sponsoring organization, document/website title, 

date of publication, website location, general description, and excerpts of the specific sections that concern pits, tanks, and/or land 

application. Note that the literature search is current as of April 1, 2014; however, there are ongoing efforts to continuously 

develop additional voluntary management practices and improve existing ones. The website addresses are current as of April 1, 

2014, but are subject to change.
April 1, 2014 Page 8

2. Methodology

Step 1

ORCR conducted a literature review/internet search and developed a list of publicly available sources of voluntary management 

practices for oil and gas exploration and production (E&P) wastes as they relate to pits, tanks, and land application/disposal. This 

information is presented in Section 3. Table 3-1 is a sampling of sources of voluntary management practices from industry, 

federal/state/local government, and non-governmental organizations. It is not intended to serve as a comprehensive list of voluntary 

management practices. 

Eighty-two voluntary management practice documents and 3 website directories were identified, along with relevant background 

material. The management practices are organized by scope: National/International, State/Provincial, or Regional. Of the 82

documents, 23 are national in scope, 6 are international, 37 are state-wide, 2 apply to a Canadian province, and 14 are regional. The 

website directories consist of 1 national and 2 regional in scope.

ORCR has not assessed all of the documents/websites identified in Table 3-1. Rather, this list was intended to assist ORCR in 

determining which documents/websites to examine in further detail.

Step 2

From the Table 3-1 list of sources of voluntary management practices developed under Step 1, ORCR focused on 12 key documents 

and 2 website directories. Table 4-1 contains a list of the 14 items with descriptions of their contents. EPA chose to focus on the key 

documents and websites that are currently widely used. The selection also was intended to provide a sampling of national, state, and 

regional voluntary management practices that were developed by industry, federal, state, and non-governmental organizations. Of the 

12 documents, 8 are national, 3 are state, and 1 is regional in scope. Of the 2 website directories, 1 is national and 1 is regional. 

Step 3

ORCR developed summaries of the 14 selected voluntary management practices sources identified in Step 2. Section 5 contains the 

following information for each source: the sponsoring organization, document/website title, date of publication, website location, 

general description, and the specific sections that concern pits, tanks, and/or land application.
April 1, 2014 Page 9

3. Sources of Voluntary Management Practices for Oil & Gas E&P Wastes

Overview

• ORCR identified 85 publicly available sources of voluntary management practices for oil and gas E&P wastes, especially as 

related to wastewater pits, tanks and land application/disposal used in deep shale gas hydraulic fracturing.

• Table 3-1 is not intended to serve as a comprehensive list of voluntary management practices documents or website directories. 

• This list is a sampling of sources of voluntary management practices from industry, federal, state, and non-governmental 

organizations.

• The primary selection criterion for inclusion in this list is the potential relevance to E&P wastewater pits, tanks, and land 

application/disposal. 

• The list is organized by the scope of the management practices: National/International, State/Provincial, or Regional. 

• Eighty-two voluntary management practices documents and 3 website directories are identified, along with relevant 

background material. 

• The 82 documents consist of 23 national/6 international, 37 state/2 provincial, and 14 regional.

• The 3 website directories consist of 1 national and 2 regional.

• Thirteen of the sources were developed by industry, 6 by federal agencies, 39 by states or local governments, and 27 by nongovernmental organizations.

• Fifty-nine of the sources apply to oil & gas E&P in general, and 26 apply specifically to hydraulic fracturing or shale gas 

development. 

• ORCR has not assessed the documents identified on the list. This list was intended to assist ORCR in determining which 

documents/websites to examine in further detail.

• The subset of 14 key sources on which EPA focused (see Sections 4 and 5) are marked in bold-type in Table 3-1.

• Note: The literature search is current as of April 1, 2014, however, there are ongoing efforts to continuously develop 

additional and improve existing voluntary management practices. The website addresses are current as of April 1, 2014, 

but are subject to change. 

It is important to note, as stated in BLM’s BMP web site, that “BMPs should be matched and adapted to meet the site-specific 

requirements of the project and local environment.”7

 7 U.S. DOI Bureau of Land Management, BMP website, http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html
April 1, 2014 Page 10

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

NATIONAL/INTERNATIONAL SCOPE

American Petroleum 

Institute (API)

Overview of Industry Guidance/Best Practices on 

Hydraulic Fracturing (HF), October 21, 2011

http://www.api.org/policy/exploration/hydraulicfracturing/upload/Hydr

aulic_Fracturing_InfoSheet.pdf

Presentation: API Introduction and API HF Standards 

for the Oil and Natural Gas Industry, presented to DOE 

SEAB Shale Gas Subcommittee, July 2011

http://www.shalegas.energy.gov/resources/071311_api.pdf

API Guidance Document HF3: Practices for 

Mitigating Surface Impacts Associated with 

Hydraulic Fracturing, January 2011

http://www.shalegas.energy.gov/resources/HF3_e7.pdf

API Guidance Document HF2: Water Management 

Associated with Hydraulic Fracturing, June 2010

http://www.shalegas.energy.gov/resources/HF2_e1.pdf

API Recommended Practice 51R: Environmental 

Protection for Onshore Oil and Gas Production 

Operations and Leases, July 2009

http://www.shalegas.energy.gov/resources/51R_e1.pdf

Onshore Access to Oil and Natural Gas Resources,

2009

http://www.api.org/policy/exploration/upload/onshore_access_primer

.pdf

Considering Good Neighbor Practices, 2008 http://www.api.org/policy/exploration/upload/Good_Neighbor_Guidel

ines.pdf

API G00004: Guidelines for Commercial Exploration 

and Production Waste Management Facilities, 

March 2001

http://www.api.org/environment-health-and-safety/environmentalperformance/environmental-stewardship/waste-managementfacilities

API E5: Environmental Guidance Document: Waste 

Management in Exploration and Production Operations, 

February 1997

http://global.ihs.com/doc_detail.cfm?currency_code=USD&customer

_id=21254E2B2C0A&oshid=21254E2B2B0A&shopping_cart_id=29

25583F2A4A2028415A5D5F260A&rid=API1&input_doc_number=%

20&country_code=US&lang_code=ENGL&item_s_key=00257647&it

em_key_date=021031&input_doc_number=E5&input_doc_title=

API 302: Waste Minimization in the Petroleum Industry: 

A Compendium of Practices, 1991

http://global.ihs.com/doc_detail.cfm?currency_code=USD&customer

_id=21254C2B2C0A&oshid=21254C2B2B0A&shopping_cart_id=29

25583F2A4A204C4F5A2D33260A&rid=API1&input_doc_number=3

02&country_code=US&lang_code=ENGL&item_s_key=00137956&it

em_key_date=081231&input_doc_number=302&input_doc_title=

Additional related standards, recommended practices 

and technical reports (includes design, inspection, 

maintenance, testing, repair of E&P equipment (e.g., 

tanks), specifications for E&P materials (e.g., drilling 

muds), remediation technologies, etc.) – See Overview 

of Industry Guidance/Best Practices on Hydraulic 

http://www.api.org/Publications/

http://www.api.org/policy/exploration/hydraulicfracturing/upload/Hydr

aulic_Fracturing_InfoSheet.pdf
April 1, 2014 Page 11

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

Fracturing (HF), October 21, 2011

Chesapeake Energy Best Management Practices [Web-based] http://www.chk.com/Operations/Best-ManagementPractices/Pages/information.aspx 

Earthworks - Oil & Gas 

Accountability Project 

(OGAP)

Best Practices Overview (includes "Alternatives to 

Pits" 

http://www.earthworksaction.org/ogapbestprac.cfm

Oil and Gas at Your Door? A Landowner’s Guide to Oil 

and Gas Development, 2nd Edition 2005

http://www.earthworksaction.org/library/detail/oil_and_gas_at_your_

door_2005_edition/

Houston Advanced 

Research Center -

Environmentally 

Friendly Drilling 

Systems Program 

(EDF)

Hydraulic Fracturing BMPs [Website Directory] http://efdsystems.org/index.php/best-management-practices

Presentation:: Environmentally Friendly Drilling, 

presented to DOE SEAB Shale Gas Subcommittee, 

June 28, 2011

http://www.shalegas.energy.gov/resources/062811_efd_presentatio

n.pdf

Article: Best Practices Database Reduces Impact of 

Drilling, Production, E&P Magazine, April 12, 2010

http://www.netl.doe.gov/kmd/RPSEA_Project_Outreach/08122-

35_HARC_Environmentally_Friendly_Drilling_article.pdf

Interstate Oil and Gas 

Compact Commission

Adverse Impact Reduction Handbook: Reducing 

Onshore Natural Gas and Oil Exploration and 

Production Impacts Using a Broad-Based Stakeholder 

Approach, 2008

http://iogcc.myshopify.com/collections/frontpage/products/adverseimpact-reduction-handbook

A Guide to Practical Management of Produced Water 

from Onshore Oil & Gas Operations in the United 

States, 2006 

http://iogcc.myshopify.com/collections/frontpage/products/a-guideto-practical-management-of-produced-water-from-onshore-oil-gasoperations-in-the-united-states-2006

Investor 

Environmental Health 

Network

Extracting the Facts: An Investor Guide to Disclosing 

Risks from Hydraulic Fracturing Operations, December 

2011

http://www.iehn.org/documents/frackguidance.pdf

Overview: Hydraulic Fracturing for Natural Gas and Oil 

Development, 2014

http://www.iehn.org/overview.naturalgashydraulicfracturing.php

U.S. DOE/NETL/ 

Argonne National Lab

Drilling Waste Management Information System 

(DWMIS) 

http://web.ead.anl.gov/dwm/index.cfm

Drilling Waste Management Technology Identification 

Module

http://web.ead.anl.gov/dwm/tim/index.cfm

Drilling Waste Management Technology Descriptions http://web.ead.anl.gov/dwm/techdesc/index.cfm

Fact Sheet – Onsite Burial http://web.ead.anl.gov/dwm/techdesc/burial/index.cfm

Fact Sheet – Land Application http://web.ead.anl.gov/dwm/techdesc/land/index.cfm

Fact Sheet – Commercial Disposal Facilities http://web.ead.anl.gov/dwm/techdesc/commercial/index.cfm

U.S. DOI Presentation: DOI Forum to Examine Best Practices for 

Hydraulic Fracturing in Oil and Natural Gas Production,

December 6, 2010 

https://www.youtube.com/watch?v=fsk4wydSBxE
April 1, 2014 Page 12

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

U.S. DOI/Bureau of 

Land Management 

(BLM)

The Gold Book: Surface Operating Standards and 

Guidelines for Oil and Gas Exploration and 

Development, 4th edition revised 2007 

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_manage

ment_practices.html%20

BLM BMP Information Sheets, August 30, 2004 http://www.blm.gov/pgdata/etc/medialib/blm/wo/MINERALS__REAL

TY__AND_RESOURCE_PROTECTION_/bmps.Par.73748.File.dat/

WO1_WO_BMPs_Technical_Information_Sheets.pdf

BLM Field Reference Guide: Visual Resource 

Management BMPs for Fluid Mineral, June 2007

http://www.blm.gov/pgdata/etc/medialib/blm/wo/MINERALS__REAL

TY__AND_RESOURCE_PROTECTION_/bmps.Par.72572.File.dat/

Visual%20Resource%20Management%20for%20Fluid%20Minerals

%20-%20Field%20Refer.pdf

Presentation: BLM Introduction to BMPs for Fluid 

Minerals, May 2006

http://www.blm.gov/pgdata/etc/medialib/blm/wo/MINERALS__REAL

TY__AND_RESOURCE_PROTECTION_/bmps.Par.37252.File.dat/

WO1_Introduction_BMP_Slideshow.ppt#277,1,Slide%201.pdf

Presentation: BLM Management Practices for Fluid 

Minerals: Production Operations, November 2006 

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_manage

ment_practices/technical_information.html

Presentation: Best Management Practices in BLM 

Planning, Leasing and Permitting, BLM Northwest 

Colorado District, presented at NRDC workshop, Oct. 

14, 2009

http://www.oilandgasbmps.org/workshops/BMPcommunity2009/pres

entations/connell.ppt

Presentation: BLM Briefing to DOE SEAB Shale Gas 

Subcommittee, May 19, 2011

http://www.shalegas.energy.gov/presentations/blm_briefing_051911

.pdf

U.S. DOI/Fish & 

Wildlife Service

Management of Oil & Gas Activities on National Wildlife 

Refuge System Lands, April 2012

http://www.fws.gov/policy/ManagementofOilandGasActivitiesHandb

ook.pdf

U.S. DOI/National 

Park Service

Operators Handbook for Nonfederal Oil and Gas 

Development in Units of the National Park System, 

October 2006

http://www.nature.nps.gov/geology/oil_and_gas/op_handbook.cfm

University of 

Pittsburgh

Shale Gas Roundtable: Deliberations, Findings, and 

Recommendations - Appendix E: Standards and Best 

Management Practices for Shale Oil and Gas 

Development, August 2013

http://www.iop.pitt.edu/shalegas/PDF/appendix-E.pdf

Full Report:

http://www.iop.pitt.edu/shalegas/PDF/90696%20SHALE%20GAS%

20FULL%20REPORT-final.pdf

STRONGER (State 

Review of Oil and 

Natural Gas 

Environmental 

Regulations)

Guidelines for the Review of State Oil and Natural 

Gas Environmental Regulatory Programs (2010 

Draft Revision)

http://www.strongerinc.org/
April 1, 2014 Page 13

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

Canadian Association 

of Petroleum 

Producers (CAPP)

Guiding Principles and Operating Practices for 

Hydraulic Fracturing, December 2012 

http://www.capp.ca/canadaIndustry/naturalGas/ShaleGas/Pages/De

fault.aspx#operating

Environmental Studies 

Research Funds 

[Canada]

Considerations in Developing Oil and Gas Industry Best 

Practices in the North [Canada], April 2009

http://www.esrfunds.org/pdf/175.pdf

E&P Forum/UNEP E&P Forum (Oil Industry International Exploration and 

Production Forum)/UNEP (United Nations Environment 

Programme Industry and Environment Centre: Joint 

E&P Forum/UNEP Technical Publication -

Environmental Management in Oil and Gas Exploration 

and Production, 1997 

http://www.ogp.org.uk/pubs/254.pdf

The E&P Forum Report No. 2.58/196: Exploration and 

Production Waste Management Guidelines, Sept. 1993 

Contact the United Nations Environment Programme for copies:

http://www.unep.org/

International Energy 

Agency (IEA)

Golden Rules for a Golden Age, May 2012 http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenr

ules/WEO2012_GoldenRulesReport.pdf

International Finance 

Corp.-World Bank 

Group

Environmental, Health, and Safety Guidelines for 

Onshore Oil and Gas Development, April 30, 2007

http://www1.ifc.org/wps/wcm/connect/topics_ext_content/ifc_externa

l_corporate_site/ifc+sustainability/sustainability+framework/environ

mental%2C+health%2C+and+safety+guidelines/ehsguidelines

STATE/PROVINCIAL SCOPE

State of CALIFORNIA Drilling and Operating Oil and Gas Wells in California, 

2002

ftp://ftp.consrv.ca.gov/pub/oil/publications/pr6s.pdf

State of COLORADO Surface Owner Brochure: Oil and Gas Well Notification, 

Consultation, and Reclamation Rules – Information for 

Oil and Gas Operators, Surface Owners and Surface 

Tenants, August 25, 2006

http://cogcc.state.co.us/General/Surface%20Owners%20Brochure.p

df

State of ILLINOIS Best Management Practices for Oil Exploration and 

Extraction

http://www.epa.state.il.us/p2/fact-sheets/bmp-oil-exploration.html

State of MARYLAND Maryland Marcellus Shale Safe Drilling Initiative Study 

Part II: Best Practices, August 2013 Draft for Public 

Comment

http://www.mde.state.md.us/programs/Land/mining/marcellus/Pages

/MSReportPartII_Draft_for_Public_Comment.aspx

University of 

MARYLAND Center 

for Environmental 

Science, Frostburg, 

MD

Recommended Best Management Practices for 

Marcellus Shale Development in Maryland: Final Report 

Submitted to Maryland Dept. of the Environment,

February 18, 2013

http://www.mde.state.md.us/programs/Land/mining/marcellus/Docu

ments/Eshleman_Elmore_Final_BMP_Report_22113_Red.pdf
April 1, 2014 Page 14

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

State of NEW 

MEXICO

Oil and Gas Manual, April 2011 http://www.nmstatelands.org/Manual_Oil_and_Gas.aspx

Pollution Prevention Best Management Practices for 

the New Mexico Oil and Gas Industry, 2000

http://www.emnrd.state.nm.us/ocd/documents/2000PollutionPrevent

ionBMPs.pdf

Pollution Prevention Pocket Guide for the New Mexico 

Oil and Gas Industry, June 1999

http://www.emnrd.state.nm.us/ocd/documents/pocketguide_003.pdf

Oil Conservation Division Environmental Handbook http://www.emnrd.state.nm.us/OCD/EnvironmentalHandbook.htm

Permit Requirements for Energy and Minerals in New 

Mexico, June 2002

http://www.emnrd.state.nm.us/OCD/documents/guide.pdf

Oil Conservation Division Enforcement Guidelines http://www.emnrd.state.nm.us/OCD/documents/Enforcement_guid

elines.pdf

Earthworks - Oil & Gas 

Accountability Project 

(OGAP)

Doing It Right: Best Oil & Gas Development Practices 

for New Mexico, January 18, 2004

http://www.earthworksaction.org/library/detail/doing_it_right_best_oil

_gas_development_practices_for_new_mexico/

State of OHIO Fact Sheet: Drilling for Natural Gas in the Marcellus and 

Utica Shales: Environmental Regulatory Basics,

January 2014

http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/EPA-factsheets/DrillingforNaturalGasintheMarcellusandUticaShales_Environ

mentalRegulatoryBasics.pdf

ODNR Best Management Practices for Oil and Gas 

Well Site Construction, June 2013

http://www.ohiodnr.com/Portals/11/publications/pdf/BMP_OIL_GAS

_WELL_SITE_CONST.pdf

Fact Sheet: Environmental Safety at the Well Site http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/Safety-at-well.pdf

ODNR Guidelines for Waste Substance Facilities,

December 18, 2013

http://oilandgas.ohiodnr.gov/industry/guidelines-for-wastesubstance-facilities

OEPA/ODNR Ohio’s Regulations: A Guide for 

Operators Drilling in the Marcellus and Utica Shales,

March 2012

http://www.epa.state.oh.us/Portals/0/general%20pdfs/Ohio%20Reg

ulations%20-

%20A%20Guide%20for%20Operators%20Drilling%20in%20the%20

Marcellus%20and%20Utica%20Shales.pdf

ODNR Oil & Gas Best Management Practices http://oilandgas.ohiodnr.gov/industry/best-managementpractices#GEN

ODNR BMP’s and Recommendations for Oil and Gas 

Activities on State of Ohio Lands, Version R2.0, January 

30, 2012

http://ohiodnr.com/portals/11/pdf/leasingbmp.pdf

Fact Sheet: Wastewater (Flowback) from Hydraulic 

Fracturing

http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/Wastewaterflowback.pdf

ODNR Bioremediation of Crude Oil Spills: A NonTechnical Field Guide, 2006

http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/Bioremediation.pdf
April 1, 2014 Page 15

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

ODNR Spreading Oil Field Brine for Dust and Ice 

Control in Ohio – A Guidance for Local Authorities, 

September 2004

http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/Brine.pdf

Harvard Law School An Ohio Landowner’s Guide to Hydraulic Fracturing: 

Addressing Environmental and Health Issues in Natural 

Gas Leases, June 16, 2011

http://www.law.harvard.edu/academics/clinical/elpc/publications/elpc

-ohio-leasing-guide-v2-june-2011-web.pdf

State of OKLAHOMA Presentation: Draft Report on Best Practices Public 

Meeting, August 7, 2013

file:///C:/Documents%20and%20Settings/HP_Administrator/My%20

Documents/EPA/O&G/BMPs/BMP%20Docs/MD%20Best_Practices

_PublicMeeting.pdf

Oklahoma Water 

Survey

Presentation: COGCC Hydraulic Fracturing, May 2011 http://cogcc.state.co.us/Announcements/Hot_Topics/Hydraulic_Frac

turing/COGCC_FRACING_briefing_052011.pdf

State of 

PENNSYLVANIA

PDCNR Guidelines for Administering Oil and Gas 

Activity on State Forest Lands, April 26, 2011

http://www.dcnr.state.pa.us/cs/groups/public/documents/document/d

cnr_004055.pdf 

PDCNR Managing Impacts of Shale Gas Development 

on State Forest Lands

http://www.dcnr.state.pa.us/forestry/NaturalGas/managingimpacts/in

dex.htm

State of TEXAS Surface Waste Management Manual, December 15, 

2010

http://www.rrc.state.tx.us/forms/publications/SurfaceWasteManage

mentManual/

Waste Minimization in the Oil Field, July 2001 http://www.rrc.state.tx.us/forms/publications/wasteminmanual/index.

php

Annotated Bibliography of Waste Minimization 

Technology for Crude Oil and Natural Gas Exploration, 

Production, and Pipeline Transportation Operations, 

July 2004

http://www.rrc.state.tx.us/environmental/environsupport/wastemin/w

asteminbibliography.php

Waste Minimization in Drilling Operations http://www.rrc.state.tx.us/forms/publications/wasteminmanual/waste

mindrillingops.php

Waste Minimization in Production and Workover 

Operations

http://www.rrc.state.tx.us/forms/publications/wasteminmanual/waste

minproduction.php

Waste Minimization Case Histories – Drilling Operations http://www.rrc.state.tx.us/environmental/environsupport/wastemin/w

asteminchdrillingops.php

Earthworks - Oil & Gas 

Accountability Project 

(OGAP)

Drill-Right Texas: Best Oil & Gas Development 

Practices for Texas, February 24, 2010

http://www.earthworksaction.org/library/detail/drill-right_texas/

State of UTAH Best Management Practices for the Oil and Gas 

Industry, March 2014

http://www.deq.utah.gov/Business_Assistance/$mart_business/guid

es/oilgas/index.htm
April 1, 2014 Page 16

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

U.S. BLM Utah State 

Office

Presentation: BMPs Used to Mitigate Environmental 

Impacts from Large-Scale Oil and Gas Projects,

November 12, 2012

https://www.youtube.com/watch?v=pSpxN_txOB0

State of 

WEST VIRGINIA

West Virginia DEP Industry Guidance – Gas Well 

Drilling/Completion, January 8, 2010

http://www.dep.wv.gov/oil-andgas/GI/Documents/Marcellus%20Guidance%201-8-10%20Final.pdf

West Virginia Erosion and Sediment Control Field 

Manual, March 1992

http://www.wvsoro.org/resources/SoilErosionSedimentControlManu

al.pdf

State of WYOMING Guideline for Closure of Unlined Production Pits, 

December 2002

http://wogcc.state.wy.us/craig/pitclose.htm

Guideline for Reclamation of Surface Areas Disturbed 

by Oil and Gas Drilling or Production Operations, 

December 2002

http://wogcc.state.wy.us/craig/RECLAMATION2A.htm

Approved Pit Treatment Companies http://wogcc.state.wy.us/craig/pittreaters.htm

Guidelines Commercial Oilfield Wastewater Disposal 

Facilities

http://deq.state.wy.us/wqd/www/Permitting/Downloads/Produced%2

0Water/Oil-Field-Pits_Active.pdf

BRITISH COLUMBIA 

OIL & GAS 

COMMISSION 

(BOGC)

Well Drilling Guideline, Version 1.6, September 2013 http://www.bcogc.ca/document.aspx?documentID=919&type=.pdf

Well Completion, Maintenance and Abandonment 

Guideline, Version 1.12, April 2013

http://www.bcogc.ca/document.aspx?documentID=920&type=.pdf

REGIONAL SCOPE

Marcellus Shale/Appalachian Region

Appalachian Shale 

Recommended 

Practices Group 

(ASRPG)

ASRPG Recommended Standards and Practices, April 

2012

http://media.marketwire.com/attachments/201204/44703_ASRPGSt

andardsandPracticesDocumentApril302012.pdf

Center for Sustainable 

Shale Development

Performance Standards, March 2013 https://www.sustainableshale.org/performance-standards/

Marcellus Shale 

Coalition (MSC)

Recommended Practices: Site Planning, Development 

and Restoration (MSC RP 2012-1), June 20, 2013

http://marcelluscoalition.org/wpcontent/uploads/2013/07/RP_Site_Planning.pdf

Recommended Practices: Drilling and Completions 

(MSC RP 2013-3), September 24, 2013

http://marcelluscoalition.org/wpcontent/uploads/2013/10/Recommended-Practice-Drilling-andCompletions-Sep-2013.pdf
April 1, 2014 Page 17

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

The Nature 

Conservancy

Paper: Scott Bearer, et. al. (2012). Environmental

Reviews and Case Studies: Evaluating the Scientific 

Support of Conservation Best Management Practices 

for Shale Gas Extraction in the Appalachian Basin. 

Environmental Practice, 14, pp 308-319

http://dx.doi.org/10.1017/S1466046612000385

Penn State University Marcellus Shale Electronic Field Guide – Best 

Management Practices

http://marcellusfieldguide.org/index.php/guide/best_management_pr

actices_in_use/

Pennsylvania 

Environmental Council

Marcellus Shale Lease Guide, June 27, 2011 http://www.pagreenlease.org/

Pinchot Institute for 

Conservation

The Marcellus Shale: Resources for Stakeholders in the 

Upper Delaware Watershed Region, December 15, 

2010

file:///C:/Documents%20and%20Settings/HP_Administrator/My%20

Documents/Downloads/Pinchot_Marcellus_Shale_BMPs.pdf

Western Pennsylvania 

Conservancy

Conservation Guidance for Landowners on Natural Gas 

Development, June 2010

http://www.waterlandlife.org/assets/Conservation_Guidance_for_La

ndowners-06032010.pdf

Fayetteville Shale 

University of Arkansas Fayetteville Shale: Reducing the Environmental Impact 

of Natural Gas Development [Website Directory]

http://lingo.cast.uark.edu/LINGOPUBLIC/

U.S. Fish and Wildlife 

Service (Arkansas 

Field Office)

Best Management Practices for Fayetteville Shale 

Natural Gas Activities, April 2007

http://www.fws.gov/arkansases/docs/AR_Natural_Gas_Pipeline_BMPs_v2_April_2007.pdf

Rocky Mountains

Natural Resources 

Law Center -

Intermountain Oil and 

Gas BMP Project

Intermountain Oil and Gas BMP Project [Website 

Directory]

http://www.oilandgasbmps.org/index.php

Presentation: Intermountain Oil and Gas BMP Project, 

October 14, 2009 

http://www.oilandgasbmps.org/workshops/BMPcommunity2009/pres

entations/mutz.ppt

Presentation: BMPs for Minimizing Environmental 

Impacts: A Resource for Communities, Government and 

Industry (SPE 147503), Abstract of paper presented at 

Society of Petroleum Engineers (SPE) 2011 Annual 

Technical Conference, October 2011

http://www.spe.org/atce/2011/pages/schedule/tech_program/docum

ents/spe147503%201.pdf

State of COLORADO Pit Design, Construction and Monitoring Requirements 

Within 3⁄4 Mile of the Rim of the Roan Plateau, June 12, 

2008

http://cogcc.state.co.us/RR_Docs_new/Policies/RoanCliffsNTO-06-

12-2008.pdf

Information on Hydraulic Fracturing http://cogcc.state.co.us/

Town of Erie, CO Oil & Gas Operations, August 2012 http://www.erieco.gov/index.aspx?NID=129
April 1, 2014 Page 18

Table 3-1. SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE WEB SITE

Cottonwood Resource 

Council, Montana

A Community Approach to Oil & Gas Development: 

Creating a Partnership for the Future, February 2013

https://www.northernplains.org/wpcontent/uploads/2013/08/FINALScenariosBMPS_2013-02-15.pdf

Earthworks - Oil & Gas 

Accountability Project 

(OGAP)

Preserving Our Public Lands: A Citizen’s Guide to 

Understanding and Participating in Oil and Gas 

Decisions Affecting Our Public Lands, Wyoming 

Outdoor Council and OGAP, 2002

http://www.earthworksaction.org/publications.cfm?pubID=92

Government of Yukon, 

Canada

Yukon Oil & Gas Best Management Practices, October 

22, 2013

http://www.emr.gov.yk.ca/oilandgas/best_management_practices.ht

ml
April 1, 2014 Page 19

4. Selected Sources of Voluntary Management Practices for Oil & Gas E&P Wastes 

Overview

• From the list of sources of voluntary management practices in Table 3-1, ORCR selected 14 key sources for further analysis.

• Table 4-1 contains a list of the 14 items with descriptions of their contents.

• Table 4-1 is not intended to serve as a comprehensive list of voluntary management practices sources, but was intended to 

provide a sampling of sources from industry, federal, state, and non-governmental organizations. 

• EPA focused on the key voluntary management practices documents that EPA believes are currently widely used.

• This list is organized by the scope of the voluntary management practices: National, State, or Regional. 

• Table 4-1 contains 12 documents and 2 website directories that were selected for review.

• Of the 12 documents, 8 are national, 3 are state, and 1 is regional in scope.

• Of the 2 website directories, 1 is national and 1 is regional.

• Five of the 14 sources were developed by industry, 3 by federal agencies, 3 by states, and 3 by non-governmental 

organizations.

• Ten of the sources apply to oil & gas E&P in general, and 4 apply specifically to hydraulic fracturing. 

• Note: The literature search is current as of April 1, 2014; however, new voluntary management practices documents are 

constantly being developed. The website addresses are current as of April 1, 2014, but are subject to change.
April 1, 2014 Page 20

Table 4-1. SELECTED SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE DESCRIPTION

NATIONAL

STRONGER (State 

Review of Oil and 

Natural Gas 

Environmental 

Regulations)

Guidelines for the Review of State Oil 

and Natural Gas Environmental 

Regulatory Programs (2010 Draft 

Revision)

http://www.strongerinc.org/

• Original guidelines were developed in 1990 by the Interstate Oil and Gas 

Compact Commission (IOGCC).

• 2010 draft revision developed by STRONGER using a multi-stakeholder process. 

The draft will be made available for public comment, revised, and submitted for 

acceptance by IOGCC.

• Provides guidance to the states on the formulation, development, and evaluation 

of oil and gas environmental regulatory programs.

• Recommends elements of a state oil and gas exploration and production (E&P) 

waste management regulatory program.

• State oil and gas E&P programs are reviewed in comparison with these 

guidelines. 

• Provides recommendations for general and administrative criteria, including 

permitting, compliance evaluation, contingency planning and spill prevention, 

public participation, financial assurance, data management, personnel.

• Provides technical criteria for waste characterization, waste management 

hierarchy, pits, land applications, tanks, and centralized and commercial disposal 

facilities.

• Provides guidelines for developing regulatory programs for abandoned sites, oil 

field NORM (naturally occurring radioactive material), stormwater management, 

and hydraulic fracturing.

American Petroleum 

Institute (API)

API Guidance Document HF3: Practices 

for Mitigating Surface Impacts 

Associated with Hydraulic Fracturing, 

January 2011

http://www.shalegas.energy.gov/resourc

es/HF3_e7.pdf

• Identifies and describes practices currently used within the industry, with the 

intent to minimize potential surface environmental impacts associated with 

hydraulic fracturing operations.

• Primary focus is on issues associated with operations in deep shale gas 

developments.

API Guidance Document HF2: Water 

Management Associated with Hydraulic 

Fracturing, June 2010

http://www.shalegas.energy.gov/resourc

es/HF2_e1.pdf

• Identifies and describes many current management practices used to minimize 

environmental and societal impacts associated with the acquisition, use, 

management, treatment, and disposal of water and other fluids associated with 

hydraulic fracturing.

• Focuses primarily on deep shale gas development issues, but also describes the 

important distinctions related to hydraulic fracturing in other applications. 

• Includes fluid handling and storage considerations.

API Recommended Practice 51R: 

Environmental Protection for Onshore 

Oil and Gas Production Operations and 

Leases, July 2009 

http://www.shalegas.energy.gov/resourc

es/51R_e1.pdf

• Identifies recommended practices for domestic onshore oil and gas production 

operations.

• Includes evaluation of existing pits and planning for new pits used for completion, 

stimulation, and workover operations; fluid handling and storage; site selection; 

design; waste and residual management; cleanup; closure and abandonment of 

facilities; Annex A – “Good Neighbor Practices.”
April 1, 2014 Page 21

Table 4-1. SELECTED SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE DESCRIPTION

API G00004: Guidelines for Commercial 

Exploration and Production Waste 

Management Facilities, March 2001

http://www.api.org/environment-healthand-safety/environmentalperformance/environmentalstewardship/waste-managementfacilities

• Developed by an E&P Waste Management Facility Guidelines Workgroup, 

coordinated by API.

• Cooperative effort among representatives of oil & gas industry, commercial 

waste management facilities, and state governments.

• Identifies design, construction, and operational options that may be used, 

depending on site-specific conditions, at facilities with the goal of protecting

human health and the environment.

• Flexible; due to diversity of settings, it is designed to offer options or alternatives 

rather than prescribe recommended practices.

• Concludes that facility operators, working with state regulators where 

appropriate, are best positioned to determine the appropriate design, operation, 

and environmental protection measures for a specific facility.

• Includes siting, design, and operating considerations for surface impoundments, 

ponds, land application, tanks, etc.

• Includes mitigation options for surface impoundments, ponds, land treatment, 

controlling releases to water, etc.

U.S. DOI/Bureau of 

Land Management 

(BLM)

The Gold Book: Surface Operating 

Standards and Guidelines for Oil and 

Gas Exploration and Development, 4th 

edition revised 2007 

http://www.blm.gov/wo/st/en/prog/energ

y/oil_and_gas/best_management_practi

ces.html%20

• Provides guidance on requirements for obtaining permit approval and conducting 

oil & gas E&P operations on Federal lands and on private surface over Federal 

minerals.

• Identifies existing requirements for construction and maintenance of oil & gasrelated infrastructure, including reserve pits.

• Recommends general operating standards for onshore drilling and production 

operations, including wastewater pits.

• Recommends reclamation and abandonment practices, including pit reclamation, 

intended to minimize environmental impacts.

U.S. DOI/National 

Park Service

Operators Handbook for Nonfederal Oil 

and Gas Development in Units of the 

National Park System, October 2006

http://www.nature.nps.gov/geology/oil_a

nd_gas/op_handbook.cfm

• For nonfederal oil & gas operators in units of the National Park System

• Includes overview of regulations and plan of operations permitting process

• Recommends “BMPs” for geophysical exploration, drilling and production 

operations, directional drilling, well closure, surface reclamation, spill control.

Earthworks - Oil & Gas 

Accountability Project 

(OGAP)

Best Practices (includes "Alternatives to 

Pits") 

http://www.earthworksaction.org/ogapbe

stprac.cfm

• Presents alternatives used during the drilling and completion phase, including 

alternatives to pits, closed-loop drilling systems, redesigned pits, directional 

drilling, flareless completions, minimizing waste.

• Recommends “BMPs” for minimizing impacts during the production phase: 

surface disturbance, visual impacts, noise, air pollution.

• Discussion of alternative management practices by other organizations: 

Intermountain Oil and Gas BMP Project (described in “Regional BMPs” section of 

this table)

Houston Advanced 

Research Center -

Hydraulic Fracturing BMPs 

[Website Directory]

• Program operated by Houston Advanced Research Center and Texas A&M 

University, with industry sponsors and stakeholders, government agencies.
April 1, 2014 Page 22

Table 4-1. SELECTED SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE DESCRIPTION

Environmentally 

Friendly Drilling 

Systems Program 

(EDF)

http://efdsystems.org/index.php/bestmanagement-practices

• Goal is to integrate “advanced technologies into systems that significantly reduce 

the impact of petroleum drilling and production in environmentally sensitive 

areas.”

• Goal is to identify, develop, and transfer “critical, cost effective, new 

technologies.”

• Website contains EDF research information and publications on BMPs.

STATE

OKLAHOMA Pollution Prevention at Exploration and 

Production Sites in Oklahoma: BMPs for 

Prevention and Control of Erosion and 

Pollution, Water Quality Series E-940, 

April 2002

http://www.occeweb.com/og/E-940.pdf

• BMPs for road construction, erosion control, and pollution prevention at typical 

exploration and production sites in Oklahoma.

• Includes sections on containment for tank batteries and pits, surface stabilization, 

drillsite pads and disposal of drilling mud, and closure of pits.

• References Oklahoma Corporation Commission rules.

NEW MEXICO Pollution Prevention Best Management 

Practices for the New Mexico Oil and 

Gas Industry, 2000

http://www.emnrd.state.nm.us/ocd/document

s/2000PollutionPreventionBMPs.pdf

• Includes case studies and alternatives for wastes generated in oil & gas 

operations.

• Includes pocket guide that can be used in the field quickly.

TEXAS Surface Waste Management Manual, 

December 15, 2010

http://www.rrc.state.tx.us/forms/publicati

ons/SurfaceWasteManagementManual/

• Technical guidelines for management of nonhazardous oil and gas wastes.

• Includes chapters on pits, discharges and land disposal, and commercial surface 

waste disposal and treatment facilities.

REGIONAL

U.S. Fish and Wildlife 

Service (Arkansas 

Field Office)

Best Management Practices for 

Fayetteville Shale Natural Gas Activities, 

April 2007 http://www.fws.gov/arkansases/docs/AR_Natural_Gas_Pipeline_BM

Ps_v2_April_2007.pdf

• Developed by a multi-agency workgroup.

• Provides guidance for natural gas exploration, drilling, and production operations 

in the Fayetteville Shale area in Arkansas. 

• Includes guidance on endangered species and migratory birds; wetlands; 

geophysical activities; construction activities (including reserve pits); disposal of 

produced water, drilling fluids, fracturing fluids; workover operations; reclamation 

and abandonment.

Natural Resources 

Law Center -

Intermountain Oil and 

Gas BMP Project

Intermountain Oil and Gas BMP Project 

[Website Directory]

http://www.oilandgasbmps.org/index.php

• Free-access website of BMPs for oil and gas development in the Rocky 

Mountain Region (Intermountain West).

• Searchable database addresses surface resources affected by oil and gas 

development.

• Database includes mandatory and voluntary BMPs currently used or 

recommended for responsible resource management in the states of Colorado, 

Montana, New Mexico, Utah, and Wyoming.

• Not intended to represent a consensus on the BMPs for specific applications.

• Database describes each BMP, documents the BMP source, provides a link to 
April 1, 2014 Page 23

Table 4-1. SELECTED SOURCES OF VOLUNTARY MANAGEMENT PRACTICES FOR OIL & GAS E&P WASTES

ORGANIZATION DOCUMENT TITLE DESCRIPTION

the BMP source, and provides supplemental information.

• Website background material includes federal, state, and local laws.
April 1, 2014 Page 24

5. Summary of Selected Voluntary Management Practices for Oil and Gas E&P Wastes as 

They Address Pits, Tanks, and Land Application

Overview

• ORCR developed summaries of the 14 selected voluntary management practices documents and website directories identified 

and described in Table 4-1.

• The summaries contain the following information for each document: 

o sponsoring organization

o document/website title

o date of publication

o website location

o general description

o excerpts of specific sections that concern pits, tanks, and/or land application

• This list is organized by the scope of the management practices: National, State, or Regional. 

• Note: The literature search is current as of April 1, 2014; however, new voluntary management practices documents are 

constantly being developed. The website addresses are current as of April 1, 2014, but are subject to change.
April 1, 2014 Page 25

List of Selected Sources of Voluntary Management Practices

NATIONAL

1 STRONGER (State Review of Oil and Natural Gas Environmental Regulations, Inc.) - Guidelines for the Review of State Oil and Natural Gas Environmental Regulatory 

Programs, 2010 Draft Revision

2 American Petroleum Institute (API) Guidance Document HF3 - Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing, January 2011

3 American Petroleum Institute (API) Guidance Document HF2 - Water Management Associated with Hydraulic Fracturing, June 2010

4 American Petroleum Institute (API) Recommended Practice 51R - Environmental Protection for Onshore Oil and Gas Production Operations and Leases, July 2009

5 American Petroleum Institute (API) G00004 - Guidelines for Commercial Exploration and Production Waste Management Facilities, March 2001

6 U.S. Bureau of Land Management (BLM) - The Gold Book: Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development, 4th edition 

revised 2007

7 National Park Service (NPS) - Operators Handbook for Nonfederal Oil and Gas Development in Units of the National Park System, October 2006

8 Earthworks - Oil & Gas Accountability Project (OGAP) - Best Practices

9 Houston Advanced Research Center - Environmentally Friendly Drilling Systems Program (EDF) - Hydraulic Fracturing BMPs [website directory]

STATE

10 Oklahoma Corporation Commission - Pollution Prevention at Exploration and Production Sites in Oklahoma: BMPs for Prevention and Control of Erosion and 

Pollution, Water Quality Series E-940, April 2002

11 New Mexico Energy, Minerals, and Natural Resources Department - Pollution Prevention Best Management Practices for the New Mexico Oil and Gas Industry, 2000

12 Railroad Commission of Texas - Surface Waste Management Manual, December 15, 2010

REGIONAL

13 U.S. Fish and Wildlife Service (Arkansas Field Office) - Best Management Practices for Fayetteville Shale Natural Gas Activities, April 2007

14 Natural Resources Law Center - Intermountain Oil and Gas BMP Project [website directory]
April 1, 2014 Page 26

1. STRONGER (State Review of Oil and Natural Gas Environmental Regulations, Inc.) - Guidelines for the Review of 

State Oil and Natural Gas Environmental Regulatory Programs, 2010 Draft Revision

Website: http://www.strongerinc.org/

General Description:

This document provides guidance to the states on the formulation, development, and evaluation of oil and gas environmental 

regulatory programs. It recommends elements of a state oil and gas exploration and production (E&P) waste management regulatory 

program. Although the guidelines are not considered voluntary management practices, the comprehensive technical criteria contained 

in the guidelines could be used as a basis for developing a voluntary management practices document. Therefore, this document is 

included in this report.

The original guidelines were developed in 1990 by the Interstate Oil and Gas Compact Commission (IOGCC). The current 2010 draft 

revision was developed by STRONGER using a multi-stakeholder process. The draft will be made available for public comment, 

revised, and submitted to IOGCC for review. A presentation on the STRONGER program was given to the SEAB Shale Gas 

Production Subcommittee.8

Specific Sections that Concern Pits, Tanks, and/or Land Application:

Section 5. Technical Criteria

5.1. General (pp. 39-40)

“These technical criteria for E&P waste management practices address waste characterization, waste management hierarchy, pits, land applications, tanks and 

centralized and commercial facilities. In most cases, these criteria are general in scope. The states should establish and implement specific performance 

standards and design specifications based on site-specific or regional differences in geology, hydrology, climate, and waste characteristics. State E&P waste 

management programs should include the following general provisions as requirements: 

a. Facilities and sites used for the storage or disposal of wastes derived from the exploration and production of oil and natural gas should be operated and 

managed at all times to prevent contamination of groundwater and surface water, soil and air, protect public health, safety and the environment, and prevent 

property damage. 

 8 STRONGER, Inc., The State Review Process, Presentation to the Secretary of Energy Advisory Board (SEAB) Shale Gas Production Subcommittee, July 13, 

2011, http://www.shalegas.energy.gov/resources/071311_stronger.pdf
April 1, 2014 Page 27

b. Facilities and sites operated specifically for the storage or disposal of exempt E&P wastes should not receive, collect, store, or dispose of any wastes 

that are listed or defined as hazardous wastes and regulated under Subtitle C of RCRA, except in accordance with state and federal hazardous waste laws and 

regulations. 

c. Disposal of E&P wastes into landfills may be considered. If such disposal is allowed, it should only be allowed where the landfill is designed to contain 

such wastes, and the E&P wastes contain no free liquids and are not mixed with non-exempt wastes prior to disposal. 

d. Technical criteria for siting, construction, and operation of E&P waste disposal facilities should be flexible enough to address site-specific or regional 

conditions based on findings by the regulatory agency. 

e. Siting Criteria 

i. States should incorporate siting requirements in statewide rules for pits, landspreading, landfilling and burial, and waste reclamation facilities. Area-wide 

rules or site-specific permits may contain additional siting conditions. 

ii. No E&P waste management facility should be located in a flowing or intermittent stream. 

iii. Where necessary to protect human health, new E&P waste management facilities should not be located in close proximity to existing residences, 

schools, hospitals or commercial buildings. The need for minimum distance criteria from residences or other buildings to the boundary of E&P waste management 

facilities should be considered. 

iv. Generally, applicable siting requirements should address such factors as depth to and quality of groundwater, wetlands, floodplains, topography, 

proximity to existing drinking water supplies and wells, geology, geologic hazards, and other environmentally sensitive areas. 

v. Siting of E&P waste management facilities should be consistent with applicable land-use requirements.” 

Specific Sections that Concern Pits

Section 4. Administrative Criteria

4.2.2. Public Participation

4.2.2.1. Notice and Records (p. 27)

“Agency records related to this program should generally be available for review by the public. Such records are to include waste disposal and pit locations and 

any required analytical data.”

4.3. Personnel and Funding

4.3.1.3. Technical (p. 37)
April 1, 2014 Page 28

“In support of field inspectors, technical personnel should be capable of mapping hydrologically sensitive areas and areas containing treatable water, and provide 

support in determining pit construction requirements and guidance in waste handling.”

Section 5. Technical Criteria

5.5. Technical Criteria for Pits

5.5.1. Definitions (p. 45)

“a. Reserve Pits

Pits used: (a) to store additional drilling fluids for use in drilling operations; and/or (b) to dispose of wastes generated by drilling operations and initial completion 

procedures. 

b. Production Pits 

i. Skimming/Settling: Pits used to provide retention time for settling of solids and separation of residual oil. 

ii. Produced Water: Pits used for storage of produced water prior to injection for enhanced recovery or disposal, off-site transport, or surface-water discharge. 

iii. Percolation: Pits used to dispose of waste liquids via drainage or seepage through the bottom and/or sides of the pits into surrounding soils. 

iv. Evaporation: Lined pits used to contain produced waters which evaporate into the atmosphere by natural thermal forces. 

c. Special Purpose Pits 

i. Blowdown: Pits used for collecting material resulting from the emptying or depressurization of wells or vessels. 

ii. Flare Pits: Pits used exclusively for flaring gas. 

iii. Emergency Pits: Pits used to contain liquids on a temporary basis due to process upset conditions. 

iv. Basic Sediment: Lined pits used for temporary storage of production wastes from tank batteries or production vessels which may contain residual oil. 

v. Workover: Pits used to contain liquids during the performance of remedial operations on a producing well in an effort to increase production.“

5.5.2. Permitting (pp. 45-46)

“a. A permitting or review process should be in place for all pits. Pits may be authorized by rule, general permit, individual permit, or as a part of an operational 

permit or program. 

b. Pits may be permitted by rule based upon specific requirements in areas where geologic, topographic, hydrologic or other conditions are similar. 

c. Authorization for a pit may be included in operational, facility, or other environmental permits (e.g., drilling, workover, gas plant, NPDES discharge). The permit 

application process may have to be expanded to include certain additional information concerning the pit (i.e., intake volume, soil type, fluid makeup, topography, 

geology, hydrology, climatology, and such other factors as may be necessary to protect human health and the environment). 

d. Construction and use of rule-authorized pits should require prior notification of the appropriate regulatory agency to ensure that proper construction, operation, 

and closure methods are used to protect human health and the environment. 

e. State programs should include provisions to accommodate approval of pits for emergency situations. “
April 1, 2014 Page 29

5.5.3. Construction (pp. 46-47)

“General standards for construction of pits should be included in area or statewide regulations and should address the following items: 

a. Size should be sufficient to ensure adequate storage until closure, taking into account historical precipitation patterns. 

b. Depth should be such that the bottom does not penetrate groundwater or such that the pit contents do not adversely impact groundwater or surface water. A 

review of available information or a study should be made of the area where the pit is to be located to determine if aquifers are present and should be protected. 

c. Berm height, slope, and material should be such that the pit is structurally sound and that pit integrity is not compromised by terrain or breached by heavy rains, 

winds, seepage, or other natural forces. 

d. If a salt section is anticipated or oil-based muds are used during a drilling program, reserve pits should be designed to accommodate those fluids. 

e. Construction standards for pits may differ depending upon the wastes they receive, the length of time they are used, and site-specific conditions. 

i. The use of production pits is declining nationally because of concerns about potential contamination of air, soils, and groundwater. In many instances, 

equipment consolidation, process modifications, or tanks can be used in lieu of pits. The use of alternatives is generally encouraged. Where production 

pits are used, they should generally be lined, except as provided below in subsection 5.5.3.e.v. 

ii. In the case of reserve and workover pits, liners should be required in certain instances based upon fluid type and site-specific characteristics (e.g., 

unconsolidated soils and/or hydro-geologic conditions that create a potential for adverse impact to surface water or groundwater, and proximity to 

environmentally sensitive areas). 

iii. Special purpose pits and other pits such as dehydration, tank drain, pipeline drip collector, and compressor scrubber pits should be lined. 

iv. Blowdown, flare and emergency pits may be unlined where the removal requirement of Section 5.5.4.k. will prevent adverse groundwater quality 

impacts. 

v. Variances to the above liner requirements should only be provided, and percolation pits should only be used, where it is clearly demonstrated there is 

minimal potential to affect adversely groundwater quality. 

vi. Liners can consist of natural or synthetic materials, should meet accepted engineering practices, and should be compatible with expected pit contents. 

f. Requirements for fencing, netting, and caging, or any other method to secure a pit, should be set by area or statewide regulations, as necessary, to protect the 

public, domestic animals, and/or wildlife. Netting of a pit is recommended as the preferred method to protect wildlife in circumstances, among others, where pits 

have oil on the surface, where pits are used for long periods, and/or where pits are located in areas with arid climates. 

g. Where feasible, reserve pits should be placed to directly receive the discharge from solids separation equipment and to collect rigwash water, spills, and leaks 

from drilling equipment.”
April 1, 2014 Page 30

5.5.4. Operational Requirements (pp. 47-49)

“a. Specific restrictions on the type of wastes that can be placed in the different types of pits should be included in area or statewide regulations. Restrictions 

should consider salinity, hydrocarbon content, pH, radionuclides associated with oil-field NORM, or other characteristics which may be detrimental to the 

environment. 

b. General security guidelines should protect the public, the environment, and wildlife. 

c. Liquids should be maintained at a freeboard level determined by the state that takes into account extreme precipitation events or other possibilities and prevents 

overtopping or un-permitted discharges. 

d. Lined pits should be operated in a manner that ensures liner integrity. 

e. Inspections and monitoring should be conducted at regular intervals or as necessary to ensure that pits meet all operating and structural integrity requirements 

and to ensure that pit contents do not adversely impact groundwater or surface water. 

f. Hydrocarbons which inadvertently accumulate in an unlined reserve pit should be skimmed off the pit at the cessation of drilling and completion operations. 

g. Separated oil or accumulated wastes should be periodically removed from unlined skimming/settling pits. 

h. Produced water pits should be used only for storage of produced water prior to injection or off-site transport. 

i. Percolation pits should be used only for disposal of produced waters and only when area or statewide restrictions established under Section 5.5.4.a. above are 

met. 

j. Evaporation pits should be periodically inspected for compliance with permitted input volumes and liner integrity. Evaporation pits should be skimmed as 

necessary to maintain an optimum evaporation rate. 

k. Blowdown, flare, and emergency pits should not be used for long-term storage or disposal. The regulatory agency should be notified promptly of the use of 

emergency pits. Fluids diverted to emergency pits should be removed as quickly as practical following the end of the emergency. 

l. Unlined basic sediment pits should not be used for storage of oily wastes; they should be replaced by lined pits or tanks. 

m. Workover pits should be open only for the duration of workover operations and should be closed within 120 days after workover operations are complete. 

n. Pit wastes that exhibit oilfield NORM above regulatory action levels should be managed in accordance with the criteria of Section 7 and any other applicable 

criteria of these guidelines.”

5.5.5. Closure (p. 49)

“a. Pits should be closed in accordance with local, state, and federal regulations and, if on private property, consistent with lease obligations. 
April 1, 2014 Page 31

b. Reserve pits should be closed as soon as practical but no later than 12 months after cessation of drilling operations. However, the closure of reserve pits 

beyond 12 months after cessation of drilling operations may be allowed in unusual circumstances if good cause can be demonstrated. 

c. Pit liquids should have free oil removed and, when appropriate, should be sampled prior to closure for salinity, hydrocarbon content, pH, radionuclides 

associated with oil-field NORM, or other characteristics which may be detrimental to the environment. On-site disposal of pit contents should be conducted in 

accordance with the landspreading, burial, and landfilling criteria of Sections 5.6. and 5.7, or by NPDES or UIC permit. 

d. Liquid and nonliquid materials not satisfying the on-site criteria for landspreading or burial (Sections 5.6. and 5.7.) should be disposed in federal or state 

approved disposal facilities. 

e. Pit sites should be capped, compacted, contoured, and vegetated where necessary, and in accordance with applicable state or area regulations to ensure 

ground support stability and to prevent erosion and ponding. 

f. Records should be permanently kept by the regulatory agency of all pit locations and should be available to the public for inspection and copying. A permit to drill 

may serve as adequate record keeping for the location of all pits within 200 feet of the well location.”

Section 6. Abandoned Sites

6.6.2. Site Remediation (p. 66)

“When reclaiming a pit, the state should determine the contents of the pit and how the pit can best be remediated. Once emptied, cleaned and tested as 

appropriate, pits should be backfilled and contoured to prevent erosion from or ponding of surface water.”

Section 8. Stormwater Management

8.3.4. Restoration and Reclamation (p. 76)

“Where appropriate, stormwater management criteria should be developed for the removal of equipment, restoration of pits, disconnection and abandonment of 

pipelines, backfilling and grading, and access road reclamation.”

Section 9. Hydraulic Fracturing

9.2. General

9.2.1. Standards (p. 77)

“Surface controls, such as dikes, pits or tanks, should meet Sections 5.5 and 5.9 of the guidelines.”
April 1, 2014 Page 32

5.10. Technical Criteria for Commercial and Centralized Disposal Facilities

5.10.2. Technical Standards and Regulatory Requirements (p. 56)

“Commercial and centralized off-site disposal facilities should meet the technical and regulatory requirements of this section and the general standards of Section 

5.1 of these criteria. Compliance with these requirements should be demonstrated in the permit application required in subsection 5.10.2.a. Because commercial 

disposal facilities use advanced methods of waste treatment and disposal, the regulatory agency should establish, where applicable, numerical requirements for 

the design of pond liners and leachate collection systems, for landfarming operations (i.e., repeated land applications), and for E&P waste reclamation facilities. 

The requirements of this section are intended to furnish the regulatory agency with sufficient and meaningful information such that permitting decisions will lead to 

no environmental impact or public health impact once the facility has commenced operations and following its closure.” 

5.10.2.2. Permitting Requirements (pp. 57-61)

“a. Any new or existing commercial or centralized facility should be required to obtain a permit from the regulatory agency to commence operation or to continue to 

operate. An individual permit should be required for E&P waste reclaimers and other commercial facilities where waste is placed on the land (e.g., in pits and in 

landfarms). A permit should be issued only upon compliance with the general requirements of Section 5.1 and the technical requirements of this section, and upon 

submittal and approval of an application that contains a Siting Plan, Construction Plan, Operating Plan, and Closure Plan. Operation of a facility should comply 

with the terms and conditions of the permit. The regulatory agency may tailor the technical requirements for all existing facilities and for centralized disposal 

facilities to the conditions present at the locations of such facilities. In the case of centralized facilities, the regulatory agency may adjust the requirements of 

Section 5.10.2.2.a. b. and c. in the light of the volume and characteristics of wastes received by the facility.”

“c. Construction Plan. In general, commercial and centralized disposal facilities should be constructed to prevent or minimize releases of wastes or waste 

byproducts to surface water, groundwater, soils, and air. Design should allow for the segregation, separation and containment of free oil to minimize emissions, 

where appropriate. The need for additional protective measures ( e.g., barriers) at facilities in close proximity to residences, schools, hospitals, or commercial 

buildings should be considered. Pits at these facilities should at least meet the construction requirements of Section 5.5.3.e. In the case of E&P waste reclamation 

facilities, construction requirements to prevent or minimize releases should also apply to wastes stored before and after reclamation. For commercial facilities, 

detailed engineering drawings and diagrams of engineered disposal facilities should be required; for centralized or one-owner facilities, such extensive 

construction details may not be needed. Construction should follow guidelines and rules adopted by the regulatory agency.”

“d. Operating Plan. Applications for permits for existing or new facilities should be accompanied by an Operating Plan that describes the wastes that will be 

accepted at the facility and the methods by which those wastes will be managed and disposed...The Operating Plan should contain the following information: 

i. Volume, rate of application, and type of material to be disposed at the facilities and the facilities that will be used to dispose of each waste stream (i.e., unlined or 

lined pits, above- or below-grade tanks, etc.)” 

“iii. Plan for routine inspection, maintenance, and monitoring to ensure and demonstrate compliance with permit requirements. At commercial and centralized 

facilities where wastes are placed on the land, such as in pits or landfarms, groundwater monitoring should be required in the absence of site-specific or facilityspecific conditions that minimize the potential for adverse impacts to groundwater. Specific plans for preventing or minimizing air emissions from sources such as 

(1) the volatilization of organic materials in the waste; (2) particulate matter (dust) carried by the wind; and (3) chemical reactions (e.g., production of hydrogen 

sulfide from sulfur-bearing wastes) should be considered. Monitoring to ensure organic wastes are treated effectively should also be required for landfarming 

operations. “
April 1, 2014 Page 33

Specific Sections that Concern Tanks:

Section 5. Technical Criteria

5.9. Technical Criteria for Tanks

5.9.1. Scope (p. 53)

“a. This section applies to permanently installed E&P waste tanks and to produced water storage tanks located at enhanced recovery operations. Where some 

waste tanks are regulated under the Spill Prevention Control and Countermeasures (SPCC) requirements of the federal Clean Water Act, states may defer to the 

SPCC requirements for those tanks.” 

“b. Except as provided in Section 5.9.3.b., this section does not apply to: 

i. condensate and crude oil tanks; 

ii. process vessels, such as separators, heater treaters, dehydrators or freewater knockouts, except that stacks or vents on such vessels should be equipped, 

where necessary, to protect migratory birds and other wildlife; and 

iii. tanks used temporarily in drilling and workover operations.” 

“c. The regulatory agency may adjust or exempt from the requirements of this section small-capacity tanks.” 

5.9.2. General Requirements (pp. 53-54)

“a. States should have information, where available, on the locations, use, 

capacity, age and construction materials (e.g., steel, fiberglass, etc.) of tanks as needed to administer and enforce state program requirements effectively. Such 

information may be obtained through registrations, inventories, or other appropriate means.” 

“b. Tanks covered by this section should not be located in a flowing or intermittent stream and should be sited consistent with applicable local land-use 

requirements.” 

“c. Tanks should be subject to spill-prevention, preventive maintenance and inspection requirements, including those of Sections 5.3.1.c. and 5.3.3. of these 

guidelines.” 

5.9.3. Construction and Operation Standards (p. 54)

“a. A principal goal of construction and operation standards for tanks is to minimize the occurrence of and the environmental impacts from spills and leaks. 

i. New tanks should be constructed in a manner that provides for corrosion protection consistent with the intended use of the tanks. All tanks covered by this 

section should be operated in a manner that provides for corrosion protection consistent with the use of the tanks. 

ii. Tanks should exhibit structural integrity consistent with their intended use. Wooden tanks should receive increased scrutiny in this regard. 

iii. Tanks should be operated in a manner that protects against overtopping. 
April 1, 2014 Page 34

iv. Secondary containment systems or other appropriate means, such as leak detection, should be employed to minimize environmental impacts in the event of 

releases.” 

“b. Covered tanks are preferred to open tanks. Open E&P waste and product tanks should be equipped to protect migratory birds and other wildlife in a manner 

consistent with the wildlife-protection criterion of Section 5.5.3.f.” 

“c. Tanks located in populated areas where emissions of hydrogen sulfide can be expected should be equipped with appropriate warning devices.” 

5.9.4. Tank Removal and Closure (pp. 54-55)

“a. Tanks should be emptied prior to their retirement and the resulting materials should be managed properly.” 

“b. Tanks and associated above ground equipment should be removed upon cessation of operations. For good cause, a state may allow tanks to be removed as 

soon as practical thereafter. Site reclamation should meet all landowner and lease obligations and any other applicable requirements.”

“c. Prior to removal, closure, or release for unrestricted use, tanks and associated piping and equipment should be surveyed for NORM as provided for in Section 

7. When regulatory action levels are exceeded, NORM and the equipment containing NORM should be managed in accordance with the state's NORM regulatory 

program (see Section 7 of these guidelines).” 

Specific Sections that Concern Land Application:

Section 5. Technical Criteria

5.6. Technical Criteria for Landspreading

5.6.1. Definition and Applicability (pp. 49-50)

“a. Landspreading is a method of treatment and disposal of low toxicity wastes in which the wastes are spread upon and sometimes mixed into soils to promote 

reduction of organic constituents and the dilution and attenuation of metals. Landfarming or multiple applications are covered under Section 5.10. 

b. These criteria apply to waste disposal at or near E&P locations and do not apply to commercial disposal operations. Commercial facilities used for disposal of 

E&P wastes are covered in Section 5.10. 

c. On-site landspreading of E&P wastes containing NORM above regulatory action levels should be prohibited.”
April 1, 2014 Page 35

5.6.2. Regulatory Requirements (p. 50)

“When landspreading practices are used at E&P sites, they should be conducted consistent with local, state, and federal regulations, and lease and landowner 

obligations. General standards for landspreading should be included in area or state regulations and should address the operational requirements of Section 

5.6.3.” 

5.6.3. Operational Requirements (pp. 50-51)

“a. Free oil should be removed from the wastes by mechanical means such as skimming or filtration before the wastes are landspread. 

b. Landspread liquids should have a pH of 6 to10 S.U. Where needed, liquids should be neutralized to obtain this range. 

c. Solid wastes should be spread evenly and disked into the soil. 

d. E&P wastes should be subject to loading rates, location restrictions, and/or other appropriate requirements that promote biodegradation of organic constituents; 

will not result in waste pooling, ponding, or runoff; will prevent the contamination of groundwater or surface waters; and will protect air quality. 

e. Where enhancement of biodegradation is desired, nitrogen and other nutrients should be added to the soil before disking. Nutrient application can be repeated 

over time. 

f. Amounts of waste added to soil during landspreading are generally limited by the electrical conductivity (EC), exchangeable sodium percentage (ESP), and 

sodium absorption ratio (SAR). The state should determine its criteria based on site-specific and waste-specific conditions. For example, some plants tolerate 

higher or lower salt levels, higher rainfall areas encourage salt movement out of the root-zone, or shallow groundwater may severely limit application. 

g. After landspreading of hydrocarbon containing waste, the waste-soil mixture should not exceed one percent by weight oil and grease, unless the state regulatory 

agency approves a less or more stringent requirement where circumstances warrant. 

h. Salt- and hydrocarbon-loading criteria apply to the final waste-soil mixture and are not an application standard. The operator should be required to demonstrate 

that these criteria are met within 12 months of cessation of drilling or production. If these criteria are not met, remediation will be required. Nothing in this 

paragraph is intended to delay any requirement for erosion control and/or site reclamation or re-vegetation. 

i. Soil analyses should be performed prior to landspreading and again upon closure of the site. Upon site closure, waste constituents should not be present at 

levels that pose a significant risk to human health and the environment. 

j. Enhanced techniques, such as repetitive disking and nutrient addition, may be needed to meet the salt and hydrocarbon criteria of the final waste-soil mixture. 

k. Under special or abnormal conditions, additional limitations and analysis requirements should be considered for wastes that may contain toxic constituents 

derived from formation liquids, cuttings, drilling muds, or drilling-mud activities. Records should be permanently maintained by the agency of all waste analyses 

conducted pursuant to such additional requirements.”

See also under Specific Sections that Concern Pits, section 5.10. Technical Criteria for Commercial and Centralized Disposal 

Facilities.
April 1, 2014 Page 36

2. American Petroleum Institute (API) Guidance Document HF3 - Practices for Mitigating Surface Impacts Associated with 

Hydraulic Fracturing, January 2011

Website: http://www.shalegas.energy.gov/resources/HF3_e7.pdf

General Description:

These national voluntary management practices were developed by the trade industry organization, the American Petroleum Institute. 

This document identifies and describes practices currently used within the industry, with the intent to minimize potential surface 

environmental impacts associated with hydraulic fracturing operations. The primary focus is on issues associated with operations in 

deep shale gas developments. A presentation on the API hydraulic fracturing standards for the oil and natural gas industry was given 

to the SEAB Shale Gas Production Subcommittee.9

Specific Sections that Concern Pits and/or Tanks:

Executive Summary (p. viii)

“7) Surface impoundments, including those used for storing fracture fluids, must be constructed in accordance with existing regulations. Depending on the fluids 

being placed in the impoundment, the duration of the storage and the soil conditions, impoundment design and construction should be impervious to prevent 

infiltration of fluids into the subsurface. All surface impoundments must be properly closed in accordance with all local, state and/or federal regulations. Materials 

removed from impoundments should be reclaimed, recycled or disposed.” 

Chapter 10. Water Management

10.3. Surface Impoundments and Storage Tanks (p. 11)

“Fluids used for hydraulic fracturing operations will generally be stored on-site in tanks or lined surface impoundments. Returned fluids, or flowback fluids, may 

also be directed to tanks or impoundments.”

“All surface impoundments, including those used for temporarily storing fracture fluids, must be constructed in accordance with existing state and federal 

regulations. In some states, an impoundment requires prior authorization from one or more regulatory agencies; and in some, a separate permit is required 

specifically for the impoundment’s functional use [10]. In addition, documentation should be kept on all materials placed in surface impoundments.”

 9 David L. Miller, API Introduction and API HF Standards for the Oil and Natural Gas Industry, Presentation to the Secretary of Energy Advisory Board

(SEAB) Shale Gas Production Subcommittee, July 13, 2011, http://www.shalegas.energy.gov/resources/071311_api.pdf
April 1, 2014 Page 37

“Larger centralized impoundments must be designed and constructed to provide structural integrity for the life of their operation, taking into consideration their size 

and extended use. Proper design, installation and operation are imperative to preventing a failure or unintended discharge off the site.”

“Depending on the fluids being placed in the completion impoundment, the duration of the storage and the soil conditions, liners may be necessary to prevent 

infiltration of fluids into the subsurface. In most states, impoundments must have a natural or artificial liner designed to prevent the downward movement of fluids 

into the subsurface. Typically, liners are constructed of compacted clay or synthetic materials like polyethylene or treated fabric that can be joined using special 

equipment. Impoundments used for long-term storage of fluids should be sited in accordance with state stream setback distances from surface water to prevent 

unauthorized discharge to surface waters.”

“Additional information may be required by regulatory authorities for centralized surface impoundments for fracture fluids. For such facilities, requirements may 

include an initial review of site topography, geology and hydrogeology, in addition to inspection and maintenance procedures—especially if such impoundments 

are within defined distances of a water reservoir, perennial or intermittent stream, wetland, storm drain, lake or pond, or a public or private water well or domestic 

supply spring.”

“In some cases, impoundments used to hold freshwater for supply purposes may be retained by the landowner for their future use. Otherwise, all surface 

impoundments should be properly closed in accordance with local, state and/or federal regulations. Materials removed from surface impoundments should be 

reclaimed, recycled or properly disposed. Refer to API Environmental Guidance Document E5, Waste Management in Exploration and Production Operations, 

Second Edition, February 1997 [11] for additional guidance on fluid impoundments and practices on

minimizing waste generation in the upstream sector.”

“In addition to surface impoundments, some operators store fluids used in, and produced from, fracturing operations in tanks. These tanks must meet applicable 

state and federal standards.”

10.1. General (p. 9)

“Using hydraulic fracturing fluids in an environmentally safe way means that the water and chemicals are sourced, 

transported, prepared, pumped into the formation, returned from the formation and disposed of in a way in that is in 

full compliance with all federal, state, and local regulations, and that minimizes impacts....”

“...water is stored in tanks or impoundments on the wellsite while waiting to be pumped...”

“...after the fracture treatment is finished, fracture fluid must be flowed back into storage tanks, lined impoundments, production equipment or other suitable 

containers...”

10.2. On-site Fluid Handling (p. 10)

“The job planning process should consider the possibility of unforeseen circumstances that

may delay the fracture operations and provide a plan for proper material management. This includes management of fluids that remain in lines, tanks and other 

containment devices after the fracturing has been completed.”

“Operators should maintain information about their fluid management and storage at the site. Such information may include:

— site design and capacity of storage impoundments and/or storage tanks;

— information about the number, as well as the individual and total capacity of, receiving impoundments and/or tanks on the well pad;
April 1, 2014 Page 38

— description of planned public access restrictions, including physical barriers and distance to edge of the well pad; and

— description of how liners are to be installed to prevent possible leakage from impoundments, in locations where liners are required by state or local regulations.”

10.4. Spill Prevention and Control (p. 12)

“When bringing fracturing materials on site, they should be stored in such a way to prevent any accidental release to the environment. These fluids may include 

both solid and liquid components. Primary containment methods commonly used include tanks, hoppers, blenders, sand separators, lines and impoundments. It is 

recommended these primary containers be visually inspected before and during the fracturing operation to ensure integrity.”

“Operators should evaluate the potential for spills and damages and use this information to determine the type and size of primary and secondary containment 

necessary.”

“Some methods to control and contain spilled substances, particularly oil, include:

— retaining walls or dikes around tanks...”

“— secondary catchment basins designed to prevent the spread of fluids that escape the primary wall or dike...”

Chapter 8. Transport of Chemicals and Other Materials (p. 8)

“The use of multi-well pads make the use of central water storage easier, reduces truck traffic, and allows for easier and centralized management of flow back 

water.”

“In order to make truck transportation more efficient, cost effective and less impactful operators may want to consider constructing storage ponds and drilling 

source wells in cooperation with private property owners. The opportunity to help a private landowner by constructing or improving an existing pond, drilling a water 

well, and/or improving the roads on their property can be a win-win situation for the operator and the landowner. It provides close access for the operator to a 

water source, and adds improvements to the property that benefit the

landowner.”

Chapter 11. Maintaining Equipment and Facilities

11.5. Pipeline Maintenance (p. 15)

“Tanks should be checked for uneven settlement of the foundation, corrosion and leaks.”

Chapter 12. Minimizing Surface Disturbance

12.2. Mitigating Impacts Associated with Site Selection (pp. 15-16)

“...equipment and materials should be positioned and stored to minimize disturbance to the environment.”
April 1, 2014 Page 39

“Subsurface soil conditions should be considered for adequate foundation support of buildings, pumps, engines, tanks and equipment used during hydraulic 

fracturing operations.”

Chapter 15. Mitigating Noise Impacts (p. 17)

“Other examples of noise mitigation techniques that can be considered with regard to hydraulic fracturing operations include:

— the placement of tanks, trailers, topsoil stockpiles or hay bales between the noise sources and receptors...”
April 1, 2014 Page 40

3. American Petroleum Institute (API) Guidance Document HF2 - Water Management Associated with Hydraulic 

Fracturing, June 2010

Website: http://www.shalegas.energy.gov/resources/HF2_e1.pdf

General Description:

These national voluntary management practices were developed by the trade industry organization, the American Petroleum Institute. 

This document identifies and describes many current practices used within the industry, with the intent to minimize environmental and 

societal impacts associated with the acquisition, use, management, treatment, and disposal of water and other fluids associated with 

hydraulic fracturing. The primary focus is on issues associated with operations in deep shale gas developments. This document does 

not address other water management issues associated with oil and gas exploration, drilling, and production.

Specific Sections that Concern Pits and/or Tanks:

Executive Summary (p. vii)

“Operators should review and evaluate practices regarding waste management and disposal from the process of hydraulic fracturing, including: The preferred 

disposition (e.g. treatment facility, disposal well, potential reuse, centralized surface impoundment or centralized tank facility) for the

basin; treatment capabilities and permit requirements for proposed treatment facilities or disposal wells; and the location, construction and operational information 

for proposed centralized flow back impoundments.”

Chapter 5. Water Use and Management Associated with Hydraulic Fracturing

5.1. Water Use and Management Associated with Hydraulic Fracturing – General (p. 9)

“The water may arrive over a period of days or weeks and may be stored on

site in tanks or lined pits.” 

“...upon completion of the fracturing operation, recovered fracture fluids in the flow back water must be separated, contained, treated, disposed of, and/or reused.”

5.2. Planning Considerations (p. 10)

“Storage—What requirements and constraints exist for water storage on site, and how do source water considerations and fracture fluid requirements affect 

storage requirements?”
April 1, 2014 Page 41

Chapter 6. Obtaining Water Supply for Hydraulic Fracturing

6.1. General (p. 13)

“Operators should conduct a detailed, documented review of the identified water sources available in an area that could be used to support hydraulic fracturing 

operations. Considerations factoring in this review should include:

— evaluating source water requirements,

— fluid handling and storage...”

6.2.1. Evaluating Source Water Requirements – Surface Water (p. 15)

“One alternative that could be considered and that may be acceptable to local water management authorities is water withdrawal programs that make use of 

seasonal changes in river flow, in order to capture water when surface water flows are greatest. This would likely involve the use of large-scale water diversion and 

storage impoundments (see Figure 6).”

“As described in more detail below, additional regulatory requirements are likely to be associated with such facilities. Diverting water to storage impoundments 

during periods of high flow allows withdrawals at a time of peak water availability which avoids impacts to municipal drinking water supplies or to aquatic or riparian 

communities. However, operators need to keep in mind that this approach will normally require the development of sufficient water storage capabilities to meet the 

overall requirements of drilling and hydraulic fracturing plans over the course of a season,

year, or perhaps even over a multi-year period (to plan for possible periods of drought).”

“Another alternative to ensuring water supply is to use abandoned surface coal mining pits for the storage of water. Having more permanent facilities such as this 

may provide for the installation of a comprehensive water distribution system that can be matched to development plans. Of course, the water quality in such 

impoundments must meet with operational requirements and will likely vary depending on the nature of the exposed overburden present in such areas. Moreover, 

these pits must meet all regulatory requirements for such surface impoundments.”

“Another simple method that can be used is to excavate low lying areas and allow for rain water harvesting. The potential use of such a method requires planning 

as it may take a long time for the excavation to fill up, depending on precipitation conditions. This option should be discussed with state, regional, or local water 

management authorities to ensure compliance with stormwater runoff program elements.”

“Figure 6—Example of Diversion Pond Construction”

6.3. Fluid Handling and Storage Considerations – General (p. 18)

“Operators may be required to provide information about their water management and storage operations at the site. Such information may include the following:

— information about the design and capacity of storage impoundments and/or tanks;

— information about the number, individual and total capacity of receiving tanks on the well pad for flow back water;

— description of planned public access restrictions, including physical barriers and distance to edge of well pad;

— how liners are to be placed to prevent possible leakage from such impoundments.”
April 1, 2014 Page 42

6.3.2. Storage in Surface Impoundments (pp. 18-19)

“If lined impoundments or pits are used for storage of fracture fluids or flow back water, the pits must comply with applicable rules, regulations, good industry 

practice, and liner specifications. However, it is important to recognize that storage impoundments containing fluids associated with fracturing operations will likely 

contain significantly larger volumes of fluids than from conventional operations. To enhance efficiency and limit the number of impounds, some operators are 

considering the use of centralized impoundments to manage flow backwater. Thus, these impoundments will be designed and constructed in such a manner as to 

provide structural integrity for the life of their operation. Proper design and installation is imperative to the objective of preventing a failure or unintended 

discharge.”

“All surface impoundments, including those used for storing fracture fluids, will be constructed in accordance with existing state and federal regulations. In some 

states, use of such an impoundment requires a prior authorization from the regulatory agency; and in some, a separate permit is required specifically for the pit’s 

explicit functional use.”

“Depending upon the fluids being placed in the impoundment, the duration of the storage and the soil conditions, an impound lining may be necessary to prevent 

infiltration of fluids into the subsurface. In most states, pits must have a natural or artificial liner designed to prevent the downward movement of pit fluids into the 

subsurface. Pits used for long term storage of fluids should be placed an appropriate distance from surface water to prevent unlikely overflows from reaching the 

surface water.”

“In addition, to ensure the safe operation and maintenance of any impoundment, an inspection and maintenance plan should be followed.”

“Additional information may be required by regulatory authorities for centralized surface impoundments for fracture fluids. For such facilities, requirements may 

include an initial review of site topography, geology and hydrogeology, especially if such impoundments are within defined distances of a water reservoir; perennial 

or intermittent stream, wetland, storm drain, lake or pond, or a public or private water well or domestic supply spring.”

6.3.3. Storage in Tanks (p. 19)

“Many operators store fluids used in and produced from fracturing operations in steel tanks, in addition to or rather than earthen pits. These tanks must meet 

appropriate state and federal standards, which may be specific to the use of the tank (e.g. use for temporary tank flow back water or more permanent production 

tank batteries).”

Chapter 7. Water Management and Disposal Associated with Hydraulic Fracturing

7.1. General (p. 20)

“In general, well permits will specify that all fluids, including fracture fluids and flow back water, must be removed from the well site. In addition, any temporary 

storage pits used for fracturing fluids must be removed as part of reclamation.”

“Operators should prepare for proper management and disposal of fluids associated with hydraulic fracturing operations. Considerations for fluid management 

should include......planned disposition (e.g. treatment facility, disposal well, reuse, centralized surface impoundment or centralized tank facility);.....and the location 

and construction and operational information for any proposed centralized flow back water surface impoundment.”
April 1, 2014 Page 43

4. American Petroleum Institute (API) Recommended Practice 51R - Environmental Protection for Onshore Oil and Gas 

Production Operations and Leases, July 2009

Website: http://www.shalegas.energy.gov/resources/51R_e1.pdf

General Description:

These national voluntary management practices were developed by the trade industry organization, the American Petroleum Institute. 

This guidance identifies recommended management practices for domestic onshore oil and gas production operations. 

Specific Sections that Concern Pits and/or Tanks:

Chapter 5. Lease Roads

5.3. Design and Construction (p. 6)

“5.3.15 Areas of excavation should be approved before the start of construction. Permits are required for opening pits on federal land and may be required on 

other public lands. Pit layout and restoration should be planned before opening of the pit.”

“5.3.16 Environmental impacts during coarse/fine borrow material extraction should be minimized. The following should be considered:

...e) maintaining a buffer of undisturbed vegetation between borrow pits and highways or other sites.”

5.5. Maintenance (p. 7)

“5.5.5 Borrow and surface materials should be readily accessible to be utilized during maintenance operations. Pits opened during construction should be used as 

a source for maintenance material, where feasible.”

Chapter 6. Producing, Injection/Disposal Wells

6.1. Completion, Stimulation, and Workover Operations

6.1.1. Planning (pp. 8-9)

“For a new well site, an effective planning process should be carried out and should incorporate the latest guidelines for waste management, pit location and 

construction, handling of water discharges, and waste disposal. The location and size of new pits and pads for completion and workover equipment should be 
April 1, 2014 Page 44

selected so as to minimize disruption of the surface resources and retain the potential for reclamation of the site. Refer to API Environmental Guidance Document: 

Onshore Solid Waste Management in Exploration and Production Operations for environmental aspects of reserve pit construction, operation and closure.”

“For an existing well site, the planning process is just as important to provide for safe and environmentally acceptable completion and workover operations. 

Existing facilities, such as pits and production equipment, should be reviewed and assessed to determine whether the facility is suitable in its present condition for 

the intended well operations or if modifications are required. For both new and existing well sites, a waste management plan for handling and storing all waste 

materials generated during completion and workover activities should be developed. Refer to API Environmental Guidance Document: Onshore Solid Waste 

Management in Exploration and Production Operations, for information on how to develop such a plan.”

6.1.6. Selection, Use, and Storage of Fuels and Completion Fluids (p. 10)

“Wherever practical, tanks or existing drilling pits should be used for completion and workover operations. Completion brines and other potential pollutants should 

be kept in lined pits, steel pits, or storage tanks. If a new earthen pit is necessary, it should be constructed in a manner that prevents contamination of soils, 

surface water, and groundwater, both during the construction process and during the life of the pit. Consideration should be given to the use of tanks or lined pits 

to protect soil and groundwater, especially for brines and oil-based fluids.”

“Normal operations should preclude oil in pits. However, in the event that well completion operations dictate use of pits containing oil for a brief period of time, they 

should be fenced, screened, netted and/or flagged, as appropriate, to protect livestock, wild game, and fowl. Refer to the Migratory Bird Treaty and Enforcement 

Improvement Act for additional guidance. Oil accumulated in pits should be promptly removed and recovered, recycled, or disposed.”

“All liquids and other materials placed in pits should be recovered, recycled, or disposed in an environmentally acceptable manner (determined by the constituents 

in the material and the environmental sensitivity of the location).”

“When operations are completed, pits not required for well operation should be closed in accordance with the environmental sensitivity of the location. The surface 

area should be restored to a condition compatible with the uses of the adjacent land area. Any pit retained should be of minimum size commensurate with well 

operations. Refer to API Environmental Guidance Document: Onshore Solid Waste Management in Exploration and Production Operations for additional 

information and permitting requirements.”

6.1.7. Stormwater Runoff (p. 10)

“Natural drainage patterns of the area should be considered in the location of equipment, pads, and pits so that stormwater runoff does not create an 

environmental hazard by erosion of base material, which could lead to equipment instability, or by flooding of pits, which could cause a discharge of oil or other 

fluids into the local surface waters.”

6.3. Well Testing

6.3.2. Flare Pits (p. 12) 

“Flare pits, sometimes called blowdown or emergency pits, should not be used for storage or disposal. The primary purpose of a flare pit is to catch any incidental 

fluid that might be associated with the gas stream that does not burn. Fluids in a flare pit should be removed daily, or as quickly as practical.”
April 1, 2014 Page 45

“Siting and construction of flare pits should minimize the risk of surface and groundwater contamination. The size of the flare pit should be proportionate to the 

volume of liquid effluent that might be expelled from the gas flare. Use of a knockout vessel should be considered.”

6.4. Plugging and Abandonment

6.4.3. Surface

6.4.3.2. Cleanup and Remediation (p. 14)

“Pits should be emptied and reclaimed to a condition similar to the rest of the reclaimed pad area. Pits should be allowed to dry or be solidified in situ before filling. 

The pit area may be mounded to allow for settling. Before removing or abandoning pipelines or flowlines, fluid displacement and line purging should be considered 

and fluid reclaimed, recycled, or properly disposed of according to fluid type.”

6.4.3.3. Soil Erosion (p. 14)

“Disturbed areas, such as roads, pits, and well sites, may need to be further remediated depending on lease

agreements.”

Chapter 7. Lease Gathering and System Lines

7.3. Design (p. 16)

“7.3.2 Lease gathering and system line design should consider the following.

....i) Optimum location for blowdown tanks, valves, etc...”

7.5. Operation and Maintenance (p. 17)

“7.5.4 Proper maintenance practices should be exercised with respect to ... blowdown tanks...”

Chapter 8. Production Water Handling Facilities

8.1. Requirement Determination (Preplanning Considerations) (p. 18)

“Water handling facilities are typically located adjacent to, or within, production facilities. Initial planning for these facilities within a field should consider future 

development potential in order to minimize surface disturbance. When practical and economic, central field locations should be considered to avoid the use of 

multiple facilities. Facility sizing should consider future throughput increases to minimize the need for additional tankage and treating vessels.”
April 1, 2014 Page 46

“Production and water handling facilities should be planned to utilize the smallest practical surface area consistent with safe, prudent, and economic operations. In 

addition, produced water may be saline and corrosive. Therefore, special care should be taken to minimize the possibility of environmental damage due to 

equipment upsets, spills, and leaks.”

8.2. Site Selection Considerations

8.2.4. Subsurface Soil Conditions (p. 19)

“Subsurface soil conditions should be considered for adequate foundation support of ... tankage...”

“Soil characteristics should be evaluated for construction of dikes, firewalls, and emergency containment areas. Lining of containment areas with compacted clay 

or synthetic liners should be considered where porous soil conditions exist or groundwater could be impacted.”

8.3. Facility Design

8.3.1. Equipment Sizing, Specifications, and Design (pp. 20-23)

f) “3) Fired lease vessels should not be located immediately adjacent to oil, gas, or any other flammable or explosive storage facilities. Facilities should have a 

grade established so that releases of flammable fluid drain away from fired equipment.

NOTE Some states have minimum distance requirements between fired vessels and storage facilities.”

“g) The following items should be considered in installing bulk storage and loading facilities.”

“1) Adequate fire/retaining walls or other containment measures should be provided around tanks, where

necessary to comply with regulatory requirements, in order to contain accidental discharges and prevent

environmental damage...”

“2) Installation of impervious foundations or liners under storage tanks should be considered to allow detection and containment of fluid releases.”

“3) Installation of high-level alarms and/or monitors should be considered on tankage.”

“i) The following items should be considered in planning, installing, and using pits, firewalls, and dikes.

1) Whenever practical, tanks should be used instead of pits.

2) Existing pits should be minimized and alternate means considered, where feasible. Pits should only be used for the purpose they were intended. Personnel 

should be advised on the specific use of the pit and what substances are allowed in the pit.

3) During the design and construction of pits and firewalls, necessary precautions should be taken to protect ground and surface water, crops, trees, livestock, and 

wildlife.

4) Pits should be designed and constructed to have sufficient freeboard, or provide adequate reserve capacity, to prevent overflow under maximum anticipated 

operating requirements and precipitation.

5) Pits should be fenced or otherwise equipped, as necessary, for public safety and to protect livestock and wildlife.
April 1, 2014 Page 47

6) Netting of pits should be considered to protect migratory birds from exposure to the pit contents if there is a potential for the pit to have an oily surface or to 

contain potentially harmful substances.

7) Burn pits should be located where prevailing winds will reduce fire hazards and smoke nuisance.

8) Storage vessels for liquid hydrocarbons, saltwater, chemicals, or other fluids that are not acceptable to be discharged into the local environment should have 

dikes constructed around their perimeters.

9) Dikes and firewalls should be constructed of material to prevent the release of fluids to the local environment during an accidental or emergency discharge from 

their original containment.

10) Consideration should be given to designing dikes and firewalls with a sufficient perimeter and wall height to contain the maximum volume of the largest vessel 

or tank contained within, and with sufficient freeboard for maximum rainfall and snow melt. Any drain lines through dikes should be equipped with valves/blinds that 

are normally closed and locked.”

j) “3) storage facilities should not be located under or near major electrical transmission lines...”

8.3.2. Equipment Location (p. 24)

“a) Production and water handling facilities should be located where they do not present a fire hazard to nearby facilities. Fired vessels, IC engines, flares, or other 

equipment that produce sparks or flames should be appropriately separated from oil and gas storage facilities...”

8.4. Construction Considerations

8.4.2. Inspection and Testing (p. 25)

“The following inspection and testing steps must be taken before initiating construction....”

“b) Upon completion, equipment and facilities should be inspected for possible leaks. If necessary, equipment should be pressure tested in accordance with 

applicable codes. If fluids are used to pressure test, collect and dispose of the fluids, refer to API Environmental Guidance Document: Onshore Solid Waste 

Management in Exploration and Production Operations for applicable information.”

“c) X-raying of welds should be considered in critical areas where extreme pressure or corrosiveness is anticipated or where potential risk to the local environment 

is of great concern.”

8.5. Operation and Maintenance

8.5.4. Corrosion Monitoring and Treatment (pp. 26-27)

“Monitoring should be considered if produced fluids are suspected of being corrosive. If produced fluids are determined to be corrosive, a corrosion abatement 

program should be considered. This is especially important in populated or environmentally sensitive areas. Operating procedures should provide for early 

identification of potential corrosion problems in failure-prone equipment. Refer to NACE MR 0175.”
April 1, 2014 Page 48

8.6. Waste and Residual Management

8.6.5. Disposal (pp. 28-29)

“The final option for management of a waste, after source reduction, recycling, and treatment options have been considered and incorporated, is disposal. The 

operator should take into consideration the long-term fate of the waste and its constituents before disposal...”

“These criteria will help determine a waste disposal option that protects human health and the environment and limits future liability for the operator. Examples of 

waste disposal options that can be considered are:

a) landspreading,

b) roadspreading,

c) on-site burial,

d) on-site pits,

e) annular injection,

f) underground injection wells,

g) regulated and permitted discharge of fluid,

h) incineration,

i) off-site commercial facility.”

8.7. Spill Prevention, Response, and Cleanup

8.7.3. Mitigation (p. 30)

“c) tanks should be checked for uneven settlement of the foundation, corrosion, and leaks...”

8.7.5. Control and Containment (p. 30)

“Some methods which can be used to control and contain discharged substances, particularly oil, include:

a) retaining walls or dikes around tanks and other spill prone equipment,

b) secondary catchment basins designed to prevent the spread of oil if it escapes the primary wall or dike...”

“Operators should evaluate the potential for spills and damages and use this information to determine the type and size of primary and secondary containment 

necessary.”

8.9. Closure and Abandonment of Facilities
April 1, 2014 Page 49

8.9.1. Purging and Flushing of Equipment Before Removal (p. 31)

“All equipment such as tankage, separation vessels, meter runs, flow lines, and pumps should be purged and flushed, as appropriate. Whenever possible, 

materials recovered should be recycled, reclaimed, or disposed. Refer to API Environmental Guidance Document: Onshore Solid Waste Management in 

Exploration and Production Operations for additional information.”

8.9.2. Equipment Removal (p. 32)

“a) Tanks, separation vessels, meter runs, surface lines, pumps, and any other exposed surface equipment should be removed. Removal of the associated 

equipment foundations should be considered.”

8.9.3. Pit Closure (p. 32)

“All pits and surface impoundments should be properly closed after they are dry and free of waste; then they should be backfilled and graded to conform to the 

surrounding terrain. Closure must also be in accordance with any local and/or state regulations. The location of closed pits should be documented. Materials 

removed from pits should be reclaimed, recycled or disposed. Refer to API Environmental Guidance Document: Onshore Solid Waste Management in Exploration 

and Production Operations for additional information. Documentation should be kept on disposed materials.”

8.9.4. Land Reclamation and Restoration (p. 32)

“Infrastructure associated with formerly producing leases, including water impoundments, power lines, metering buildings, compression facilities and tank batteries 

must be removed and the footprints or lands disturbed by these facilities and associated foundations reclaimed unless the surface owner requests that items such 

as impoundments or water wells be kept.”
April 1, 2014 Page 50

5. American Petroleum Institute (API) G00004 – Guidelines for Commercial Exploration and Production Waste 

Management Facilities, March 2001

Website: http://www.api.org/environment-health-and-safety/environmental-performance/environmental-stewardship/wastemanagement-facilities

General Description:

These national voluntary management practices were developed by an E&P Waste Management Facility Guidelines Workgroup, 

coordinated by the trade industry organization, the American Petroleum Institute. This Workgroup was a cooperative effort among 

representatives of the oil & gas industry, commercial waste management facilities, and state governments. Although most E&P 

wastes are managed on-site, according to this document, approximately one percent of these wastes are managed by commercial and 

centralized waste management facilities located off-site. This document identifies design, construction, and operational options that 

may be used, depending on site-specific conditions, at these facilities with the goal of protecting human health and the environment.

Specific Sections that Concern Pits/Surface Impoundments:

Chapter 2. Siting, Design, and Operating Considerations

2.2. Basic Construction and Technical Considerations

2.2.3. Evaporation ponds and other surface impoundments (pp. 13-14)

“Where climate allows, evaporation ponds and surface impoundments can be very effective for managing certain waste types. In designing and operating 

evaporation ponds or surface impoundments, it may be appropriate to consider the amount of salt, oil and grease, and metals in the waste streams managed in 

this manner, and how they may affect the dried, residual material and/or liner, if applicable. Wastes with a high oil or hydrocarbon content may be inappropriate for 

treatment in evaporation ponds or other surface impoundments unless the hydrocarbons are removed prior to placement in the impoundment.”

“Design considerations. Evaporation ponds and other impoundments should be designed to minimize the potential leakage of waste material or leachate from the 

treatment unit and to prevent migration of wastes into nearby water resources. Appropriate measures include proper siting of the facility (section 2.1) and

consideration of site-specific characteristics. In de signing the facility, an appropriate combination of the following protective measures should be considered:

 Dike s , be rms , a nd fre e boa rd;

 Cla y or s ynthetic liners;

 Le a cha te colle ction a nd re mova l s ys te ms ;

 Le a k de te ction s ys te ms ;

 Groundwa te r monitoring to ide ntify le a cha te migra tion (whe re de e me d a ppropria te ); a nd/or

 Wildlife prote ction me a sure s (see section 2.3.4).”
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“Operating considerations. Evaporation ponds and surface impoundments should be operated in a manner that prevents off-site migration of waste or waste 

components from the treatment unit. Facility operators should consider the need for:

 Routine visua l ins pe ction of the tre a tme nt units to assure adequate freeboard and that wildlife protection measures are intact (where applicable); and

 Routine s kimming ope ra tions to re move floa ting wa s te compone nts , the re by re ducingvolatilization of free hydrocarbons.”

2.2.4. Percolation ponds (p.14)

“Percolation ponds are used to allow produced water to percolate into the ground. The pond should act only as a holding facility while gravity allows the water to 

percolate or seep through the soil or other unconsolidated medium. Percolation ponds are allowed in only a few states; check applicable state regulations for 

information on their design. Typically, states will permit percolation ponds only in areas where groundwater is quite deep or absent, or separated by geologic 

barriers, such as clay or shale zones, to minimize the potential for impact from the produced water.”

Chapter 4. Water Issues

4.1. Introduction (pp. 34-35)

“Figure 4.1 provides a qualitative assessment matrix of the factors that may increase risks of surface water or groundwater contamination.”

“Figure 4.1: Qualitative Assessment of Exposure Probabilities and Magnitudes from Potential E&P Waste Management Facility Releases to Water”

4.2. Mitigation Options Available for Controlling Releases to Water

4.2.2. Containing waste and waste leachate (pp. 36-38)

“Liners. A liner is a continuous barrier that covers the area likely to be in contact with waste so that the constituents in the waste are prevented from migrating to 

surrounding native soils. Liners may be used to control or prevent seepage out of or into a structure. Liners are made either from earthen materials (e.g.,

clay, bentonite) or synthetic materials (e.g., plastic). Liners made of natural materials are relatively inexpensive in comparison to those made of synthetic materials, 

but may be inappropriate depending upon the site-specific characteristics of the facility. Liners made from natural materials typically exhibit low permeability 

characteristics and will effectively contain most types of material. However, some wastes or site conditions may necessitate an impermeable synthetic liner.”

“Single or multiple layers of liners can be installed at a facility, based on the facility’s potential to contaminate water resources. State regulations may specify the 

thickness and composition of liners. A number of factors affect the selection of liner materials and the number of liner layers at a site, including permeability of 

naturally occurring soils, chemical compatibility with waste leachate, aging and durability characteristics, stress and strain characteristics, ease of installation, and 

facility potential to affect groundwater resources based on its topography. For example, if a facility is in a low groundwater vulnerability region, a natural clay liner 

could be appropriate to protect water resources. If a facility operates in a high groundwater vulnerability area, a double liner system may be more appropriate to

ensure protection of water resources.”

“Given the diverse operating environments of E&P waste management sites, liners may not be necessary at all facilities. If installed, liner systems should extend 

under the entire treatment unit area. The visible portion of liners should be checked periodically to assure that it is not damaged or torn. Whenever wastes
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are removed from the impoundment, the liner should be checked for visible damage before new wastes are placed into the impoundment. A liner’s overall 

effectiveness depends on its thickness and permeability, as well as other factors discussed above.”

“Dikes, berms, and levees. Open-cell treatment units should be designed to prevent storm water run-on and the flow of liquids over the top of a unit (overtopping). 

This can be accomplished by constructing and maintaining dikes, berms, or levees. These containment structures should be constructed of materials

that are resistant to seepage and erosion, and that have favorable compaction characteristics. Organic soils are not suitable because of high compression, low 

strength, and unpredictable permeability.”

“Secondary containment. Secondary containment consists of placing a barrier – such as a vault, leakproof liner, or double-walled structure – around a tank or 

container that stores, treats, or handles waste. To ensure that E&P waste management sites present minimal release potential to water resources, one of the

following secondary containment devices can be used:

 ̈ Dikes, berms, and levees, or a concrete pad with a curb;

 ̈ An external liner that completely surrounds the tank with an impermeable material;

 ̈ A vault (the tank rests in an underground chamber usually constructed with concrete floors and walls and an impermeable cover); and/or

 ̈ A double-walled tank (the tank is completely enclosed inside another tank with a leak detection monitoring system installed between the two).

Requirements can vary depending on geography, proximity to groundwater and surface water resources, and the type of waste being stored or treated. Secondary 

containment devices may be built with native soils, clays, bentonite, or synthetic materials.”

“Leachate collection and removal. Leachate collection and removal systems can differ greatly in design and numbers of components depending on the location in 

which the facility operates. A double leachate system, which may be appropriate in some cases, has two liners with a leachate collection system on top of each 

liner. The top system rests on the top liner, and the second between the top and bottom liner. Figure 4.2 illustrates this type of system, which would normally be 

used at an E&P facility only in cases of substantial leachate volume and very high groundwater contamination risk. A single leachate collection system may be 

appropriate in many situations to prevent liquids from seeping through a liner.”

“Figure 4.2: Illustration of a Double Liner and Leachate Collection System”

“In some lower risk areas, liners may not be necessary to protect groundwater resources and may be prohibitively expensive. In these areas, a system of drains 

(such as that shown in Figure 4.3) to prevent contact of the waste and the water table may be adequate.”

“Figure 4.3: Illustration of a Drainage System”

4.2.3. Applying overflow protection measures (p. 39)

“Adequate freeboard. Overflow from open-cell treatment units can be prevented through the use of dikes and berms (see section 4.2.2), in conjunction with 

ensuring a minimum distance (called freeboard) between the surface and the top of the unit. Freeboard is designed to prevent overflow during high winds

or rainstorms. Freeboard should generally be capable of retaining the contents of the open-cell treatment unit during a particularly heavy rainfall event (e.g., a 100-

year storm).”

“In-series cells. Where space is available, another overflow protection option is a series of cells connected by piping. The second or subsequent cells would 

normally be empty, but would receive excess material via piping when the first cell reached capacity. This method is suitable for liquid wastes or cases where

the excess volume is due to heavy rainfall.”
April 1, 2014 Page 53

Appendix B: Summary of State Regulations Related to E&P Waste Management Facilities

Surface Impoundment regulations:

California – p. 50 of API document

Colorado – p. 52 of API document

Louisiana – p. 54 of API document

New Mexico – p. 56 of API document

Oklahoma – p. 58 of API document

Texas – p. 60 of API document

Utah – p. 61 of API document

Wyoming – p. 62 of API document

Appendix D: Glossary

“Evaporation Pond- Any unit specifically designed for the holding and evaporation of water. This type of disposal results in the concentration of salts, metals, and 

residual hydrocarbons.” (p. 70)

“Impoundments- A facility or unit consisting of a natural topographic depression, man-made excavation, or diked area formed primarily of earthen materials 

(although it may be lined with man-made materials), designed to hold an accumulation of liquid or solid waste. Runoff and containment areas are also

considered to be surface impoundments.” (p. 71)

“Mixing basin- A surface impoundment used to homogenize the liquid and solid phases of waste prior to separating the liquids and solids for further treatment or 

disposal.” (p. 71)

“Percolation ponds- A type of unit used to dispose of liquids, usually produced water. Percolation ponds allow the liquids to drain or seep into the sides or through 

the bottom of the pond into the surrounding soils for disposal. These are only used in areas where the groundwater is very deep or nonexistent.” (p. 72)

Note: Chapter 3 Air Emissions and Related Issues (pp. 24-31) includes mitigation options designed to control air emissions from aerated surface impoundments, 

evaporation ponds, mixing basins, etc.

Specific Sections that Concern Tanks:

Chapter 2. Siting, Design, and Operating Considerations

2.2. Basic Construction and Technical Considerations

2.2.8. Tank storage (pp. 15-16)
April 1, 2014 Page 54

“Tanks are stationary devices (as opposed to portable containers) used to store or treat waste. Tanks are widely used for liquid waste storage or accumulation. 

Tanks can be aboveground or underground, although aboveground tanks are preferred because they are easier to inspect and maintain. In order to ensure that a 

tank system can hold waste for the tank’s intended lifetime, the facility should ensure that the tank is properly designed. The tank system and its components 

should be designed with adequate foundation, structural support, and corrosion protection to prevent it from collapsing or leaking. Leak detection and prevention 

provisions – such as a concrete base, leak detecting bottom, or a raised foundation – should also be considered.”

“Installation considerations. New tank systems should be inspected prior to use to ensure that the tank was not damaged before or during installation. All new 

tanks and ancillary equipment should be tested to make sure that there are no leaks; any leaks discovered must be repaired before the tanks are covered,

enclosed, or placed in use.”

“Design/Operating considerations. Tanks should always be operated in a manner that minimizes or eliminates releases. Waste characteristics should be consistent 

with the design of the tank (e.g., wastes that may react with the tank components should not be placed in the tank). Because the loading or filling of tanks may 

create the potential for spills or releases of waste into the environment, the following prevention or containment measures should be considered:

 ̈ Spill prevention controls (such as valves) designed to prevent the backflow of waste during filling;

 ̈ Overfill prevention controls, such as alarms that sound when the waste level in the tank exceeds a specified point, or valve systems that automatically close when 

overfill is likely;

 ̈ When appropriate, emissions controls, such as vapor recovery units or flares;

 ̈ Sufficient space within an uncovered tank between the surface of the waste and the top of the tank (minimum freeboard);

 ̈ Secondary containment (dikes or berms) that is capable of containing the entire volume of the tank; and/or

 ̈ Regular inspection of site security measures.”

“Where tanks contain wastes or liquids that may be flammable (regardless of whether they are exempt E&P wastes under RCRA), facilities should consider state 

and local fire regulations that may affect tank operations.”

Chapter 4. Water Issues

4.2. Mitigation Options Available for Controlling Releases to Water

4.2.2. Containing waste and waste leachate (p. 36)

“Tanks. Tanks can be used to replace surface impoundments that may pose higher risks to human health and the environment. For information on proper 

installation and design/operating considerations, see section 2.2.8.”

4.2.3. Applying overflow protection measures (p. 39)

“Overfill protection. Overfill protection controls for tanks, such as high-level alarms, can reduce the likelihood of spills. Several controls are available to facilities. 

For example, some systems have backflow protection to prevent waste from flowing out of tanks. Similarly, automatic shut-off valves will close when a tank 

becomes too full and an overflow is imminent. Visual and/or audible high-level alarms may be employed alone or in conjunction with these valve-based overflow 

controls.”
April 1, 2014 Page 55

4.2.4. Installing leak detection methods (p. 39)

“Leak detection devices can be highly effective in alerting a facility operator to problems with the integrity of a storage tank. Leak detection can be monitored on 

either a continuous or periodic basis, as appropriate for the age of the tank, the material in the tank, and site-specific conditions.”

“Continuous leak detection monitoring. Common continuous leak detection monitoring provisions for tanks include a concrete base, leak detecting bottom, and 

raised foundation. More sophisticated leak detection methods available for both tanks and liners include alarms, inventory control, acoustic emissions testing, 

volumetric measurement, and interstitial space monitoring (interstitial methods range from a simple dip stick to a continuous automated vapor or liquid sensor that 

is permanently installed in the system). Leak detection systems are most effective when integrated with leak containment systems and should be done so based 

on the site-specific characteristics present at a given facility. Leak detection systems by themselves only alert the facility operators to the existence of a discharge. 

When combined with leak containment structures, however, it is less likely that waste or leachate will be discharged to the environment. Trained and experienced 

installers should be consulted when employing continuous leak detection systems.”

“Periodic leak detection monitoring. If a facility decides continuous leak detection monitoring systems are not feasible, periodic leak detection should be 

considered. Periodic leak detection involves checks or tests at regular intervals to assess the potential for waste discharge or tank bottom failure. Visual

inspection is the most common form of periodic leak detection. When used, facilities should ensure that written records are maintained, interpreted, and reviewed. 

One drawback to visual inspection is the inability of operators to visually inspect the bottoms of many types of tanks. In these cases, other techniques that do not 

require tank entry, such as acoustic emissions monitoring, may be appropriate.”

Specific Sections that Concern Land Application:

Chapter 2. Siting, Design, and Operating Considerations

2.2. Basic Construction and Technical Considerations

2.2.1. Traditional land treatment (pp. 12-13)

“Land treatment includes land farming, land spreading, and other similar waste application methods. Land treatment units generally utilize biodegradation to treat 

waste. Except in certain circumstances, traditional land treatment may be inappropriate for liquid wastes. Where biodegradation is important to the treatment 

process, the treatment unit must be designed and operated properly to facilitate the biodegradation process.”

“Design considerations. Land treatment units should be equipped with controls to prevent rain water and other liquids from running onto the unit (creating leachate) 

and to prevent leachate from running off the unit and carrying waste components into surrounding soils and nearby waters. Controls to prevent wind gusts from 

blowing small particles off land treatment units into the air and onto surrounding property and surface water should also be employed. As part of these efforts, 

facilities should consider the following:

 ̈ Wind dispersal controls (e.g., decreased agitation, sprinkler system [see section 3.2]);

 ̈ Run-on and runoff controls (e.g., adequate freeboard, dikes, berms [see section 4.2]); and/or
April 1, 2014 Page 56

 ̈ Proper moisture content in the soil-waste matrix.”

“Operating considerations. Several operational activities are key to the successful operation of a land treatment unit. Land treatment units should be operated 

considering the following:

 ̈ Preventing pooling of oily liquids;

 ̈ Controlling the rate and method of waste application;

 ̈ Controlling soil chemistry and moisture content; and

 ̈ Enhancing microbial, chemical, and physical reactions appropriate for proper waste treatment.”

“The American Petroleum Institute has developed several publications that may be helpful in establishing operational considerations for land treatment units. 

These include “Evaluation of Limiting Constituents Suggested for Land Disposal of E&P Wastes” (API Pub. No. 4527), “Criteria for pH in Onshore Solid

Waste Management in E&P Operations” (API Pub. No. 4595), and “Metals Criteria for Land Management of E&P Wastes” (API Pub. No. 4600). These publications 

may be ordered by calling API at 202-682-8000 or through the API web site at www.api.org/cat.”

2.2.2. Hybrid land treatment (p. 13)

“Hybrid land treatment is a technique that involves the placement of E&P waste in an excavated cell, washing the waste with freshwater to remove salts, injecting 

the resulting water into a Class II well, and then drying the remaining solids. The primary objective of this treatment method is the reduction of total chlorides to 

below regulatory criteria to allow the waste to be reclassified as reuse material. Some biodegradation of hydrocarbons in the waste also occurs, but this is not the 

primary objective of this treatment method. This technique is used most frequently in the State of Louisiana.”

“Design considerations. To facilitate the washing process, the treatment cell should be lined with a leachate collection system. The liner material and thickness 

should be appropriate to the hydrologic conditions at the site. Where wastes with higher hydrocarbon content are accepted, the need for additional separation prior 

to loading wastes or skimming of free oil during the washing process should be considered.”

Appendix B: Summary of State Regulations Related to E&P Waste Management Facilities

Land Treatment regulations:

California – p. 51 of API document

Colorado – p. 52 of API document

Louisiana – p. 55 of API document

New Mexico – p. 57 of API document

Oklahoma – p. 58 of API document

Texas – p. 60 of API document

Utah – p. 61 of API document

Wyoming – p. 62 of API document

Appendix D: Glossary
April 1, 2014 Page 57

“Hybrid land treatment- A modification of land treatment whereby freshwater is used in the process to remove salts from the waste. Once the freshwater has been 

mixed with the waste, the salt-containing water is removed from the land treatment area for injection or discharge in accordance with applicable permits. This 

process may be repeated until the desired level of salt concentration is reached in the waste.” (p. 71)

“Land farming- This term is typically used for a process similar to that defined as land spreading, but where multiple applications of waste are made to the same 

parcel of land over time. To assure appropriate biodegradation of the hydrocarbons in waste, the waste or soil is often amended with fertilizer and may be tilled 

periodically.” (p. 71)

“Land spreading- A one-time, controlled application of waste to the land whereby the waste is spread over a wide area of land surface and is subsequently 

degraded, transformed, or immobilized and left in place.” (p. 71)

“Land treatment- A dynamic process involving the controlled application of nonhazardous E&P waste onto or into the aerobic surface soil horizon, accompanied by 

continued monitoring and management to alter the physical, chemical, and biological state of the waste. Site, soil, climate, and biological activity interact as a 

system to degrade and immobilize waste constituents thereby rendering the area suitable for the support of vegetative growth and providing for beneficial future 

land use.” (p. 71)

“Road spreading or mixing- The practice of applying certain E&P wastes onto roadways or mixing with excavated native materials to form road paving materials.” 

(p. 72)

Note: Chapter 3 Air Emissions and Related Issues (pp. 24-31) includes mitigation options designed to control air emissions from land treatment units (land 

spreading, land farming, road mixing). 
April 1, 2014 Page 58

6. U.S. Bureau of Land Management (BLM) - The Gold Book: Surface Operating Standards and Guidelines for Oil and Gas 

Exploration and Development, 4th edition revised 2007

Website: http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html%20

General Description:

This document developed by BLM provides operators with a combination of guidance and standards for ensuring compliance with 

agency policies and operating requirements. It includes requirements and voluntary management practices for conducting oil & gas 

exploration and production operations on Federal lands and on private surface over Federal minerals.

Specific Sections that Concern Pits and/or Tanks:

Chapter 1. Introduction

Environmental Best Management Practices (pp. 2-3)

“Environmental Best Management Practices (BMPs) are state-of-the-art mitigation measures designed to provide for safe and efficient operations while minimizing 

undesirable impacts to the environment. Proper planning and consultation among the operator, surface management agency, and non-Federal surface owner, and 

the proactive incorporation of environmental Best Management Practices into the APD [Application for Permit to Drill or Reenter] Surface Use Plan of Operations 

by the operator, will typically result in a more efficient APD and environmental review process, increased operating efficiency, reduced long-term operating costs, 

reduced final reclamation needs, and less impact to the environment.”

Chapter 3. Permitting and Approval of Lease Operations

Surveying and Staking (p. 9)

“When an APD is submitted, staking must include the...reserve pit...unless a variance is granted.”

“The well location plat must describe the location of the surface disturbances and their proximity to the nearest section lines, lease lines, ownership, or special use 

area boundaries...”

Chapter 4. Construction and Maintenance (p. 15)

“Construction and maintenance must be performed to standards that ensure the long-term health and productivity of the land. The operator’s representative must 

ensure compliance with all plans and designs. The representative should be designated prior to construction; be accessible to the surface management agency 
April 1, 2014 Page 59

authorized officer; have immediate access to an approved copy of the Application for Permit to Drill (APD), including all maps, drawings, templates, and 

construction standards; and have the authority to make changes at the request or order of the BLM or surface management agency.”

Well Sites

Site Selection and Design (p. 15)

“To the extent permitted by the geologic target, well spacing, and drilling and production technology, the locations selected for well sites, tank batteries, pits, and 

compressor stations should be planned so as to minimize long-term disruption of the surface resources and existing uses, and to promote successful reclamation. 

Design and construction techniques and other practices should be employed that would minimize surface disturbance and the associated effects of proposed 

operations and maintain the reclamation potential of the site.”

“The site layout should be located and staked in the most level area, off narrow ridges, and set back from steep slopes, while taking into consideration the geologic 

target, technical, economic, and operational feasibility, spacing rules, natural resource concerns, and safety considerations.”

“Operations should also be avoided or properly mitigated in riparian areas, floodplains, playas, lakeshores, wetlands, and areas subject to severe erosion and 

mass soil movement.”

“The advantages gained by a good well site or tank battery location should not be negated by the adverse effects of the access road location.”

Construction (p. 16)

“The drill rig, tanks, heater-treater, and other production equipment are not to be placed on uncompacted fill material. The area used for mud tanks, generators, 

mud storage, and fuel tanks should be at a slight slope, where possible, or a suitable alternative, such as ditching, should be used to provide surface drainage 

from the work area to the pit.”

“To reduce erosion and soil loss, it may be appropriate to divert storm water away from the well location with ditches, berms, or waterbars above the cut slopes 

and to trap well location runoff and sediments on or near the location through the use of sediment fences or water retention ponds.”

Reserve Pits (pp. 16-18)

“Reserve pits are generally used for storage or disposal of water, drill mud, and cuttings during drilling operations. The pit should normally be located entirely in cut 

material. Avoid constructing reserve pits in areas of shallow groundwater. Reserve pits should not be constructed in natural watercourses. Water courses include 

lake beds, gullies, draws, streambeds, washes, arroyos, or channels that are delineated on a 1:24,000 USGS quadrangle map or have a hydrologic connection to 

streams, rivers, or lakes.

For reserve pit construction on sloping sites, the preferred method is to locate the pit on the drill pad next to the high wall. Pits are constructed totally in cut at such 

locations. If this is not possible, at least 50 percent of the reserve pit should be constructed below original ground level to help prevent failure of the pit dike. Fill 

dikes should be properly compacted in lifts. The necessary degree of compaction depends on soil texture and moisture content. The pit should be designed to 

contain all anticipated drilling muds, cuttings, fracture fluids, and precipitation while maintaining at least 2 feet of freeboard.
April 1, 2014 Page 60

Pits improperly constructed on slopes or poor soil types may leak along the plane between the natural ground level and the fill. There is a significant potential for 

pit failure in these situations. When constructing dikes for pits or impoundments with fill embankment, a keyway or core trench should be excavated to a minimum 

depth of 2 to 3 feet below the original ground level. The core of the embankment can then be constructed with compacted, water-impervious material.

To prevent contamination of ground water and soils or to conserve water, it is recommended that operators use a closed-loop drilling system or line reserve pits 

with an impermeable liner, particularly when it is anticipated that pits will contain moderate or high levels of hydrocarbons and chloride, or the pits are located in 

areas of shallow groundwater or porous soils over fractured bedrock aquifers. 

Pits can be lined with synthetic liners or other materials such as bentonite or clay. Impermeable liners should have a permeability of less than 10-7cm/sec. Liners 

must be installed so that they will not leak and must be composed of materials compatible with all substances to be placed in the pit. Synthetic liners with a 

minimum thickness of 12 mils and resistance to ultraviolet radiation, weathering, chemicals, punctures, and tearing are most commonly used, although some 

States may require liners that are thicker. Suitable bedding material, such as sand, clay, or felt liners should be used in areas where the base rock might puncture 

the liner.

Depending on the proposed contents of the pit and sensitivity of the environment, the surface management agency may require a leak detection system or the use 

of self-contained mud systems with the drilling fluids, mud, and cuttings being transported to approved disposal areas.

Reserve pits should be appropriately fenced to prevent access by persons, wildlife, or livestock. During drilling in active livestock areas, the reserve pit must be 

fenced with an exclosure fence on three sides and then fenced on the fourth side once drilling has been completed. Refer to Figure 1 for recommended fence 

construction standards in active livestock areas. In areas where livestock will not be present, other types of fences may be appropriate.

The fence should remain in place until pit reclamation begins. After cessation of drilling and completion operations, any visible or measurable layer of oil must be 

removed from the surface of the reserve pit and the pit kept free of oil. In some situations and locations, precautions, such as netting, may be required in order to 

prevent access and mortality of birds and other animals.”

Chapter 5. Drilling and Production Operations

Subsequent Well Operations (p. 37)

“Operations requiring the prior approval of BLM’s authorized officer include: deepening, plugging back, non-routine fracturing jobs, recompletion in a different 

interval, and conversion to a service well. If there is additional surface disturbance, the proposal must include a Surface Use Plan of Operations. A subsequent 

report of operations must also be filed for these operations following completion of the work.”

“Operations, such as routine fracturing or acidizing jobs or recompletion in the same interval, do not require prior approval if such operations do not involve 

additional surface disturbance and conform to standards of prudent operating practice. However, a subsequent report of operations must be filed for these 

operations.”

Approval Procedures (p. 38)

“When additional surface disturbance is proposed that was not previously authorized for the well pad or right-of-way, a description of any subsequent new 

construction, reconstruction, or alteration of existing facilities, including roads, dam sites, flowlines and pipelines, pits, tank batteries, or other production facilities 

on any lease, must be submitted to the authorized officer for environmental reviews and approval.”
April 1, 2014 Page 61

Measurement of Production (p. 38)

“No oil is to be diverted to a pit except in emergency situations or with prior approval from the authorized officer. Oil in the pit must be recovered promptly, and the 

pit must be kept reasonably free from surface accumulations.”

Disposal of Produced Water (pp. 38-39)

“Produced water from leasehold operations will be disposed of by subsurface injection, lined or unlined pits, surface discharge into channels or impoundments, or 

other methods, including beneficial use, acceptable to the authorized officer and in accordance with the requirements of Onshore Order No. 7, Disposal of 

Produced Water, and other Federal or State regulations.”

“In cases of water disposal into pits or other impoundments, the structures must conform to approved construction requirements in accordance with Onshore Order 

No. 7, BLM Manual 9172, and applicable State agency requirements.”

“Pits, water impoundments, and surface discharges that present a potential hazard to humans, livestock, wildlife, and other resources should be subject to 

appropriate mitigation, such as fencing, netting, caging, or covers, as appropriate. Refer to Figure 1 for exclosure fence construction standards.”

Pollution Control/Hazardous Waste (p. 39)

“Containment structures sufficiently impervious to prevent a discharge to waters of the United States, such as containment dikes, containment walls, drip pans, or 

equivalent protection actions are to be constructed and maintained around all qualifying bulk oil storage facilities, including tank batteries, consistent with the 

Environmental Protection Agency’s Spill Prevention, Control, and Countermeasure (SPCC) regulation (40 CFR 112). The containment structure must have 

sufficient volume to contain, at a minimum, the content of the largest storage tank containing liquid hydrocarbons within the facility/battery and sufficient freeboard

to contain precipitation, unless more stringent protective requirements are deemed necessary by the authorized officer. Drip pans should be routinely checked and 

cleaned of petroleum or chemical discharges and designed to prevent access by wildlife and livestock.”

“Containment dikes are not to be constructed with topsoil or coarse, insufficiently impervious spoil material. Containment is strongly suggested for produced water 

tanks.”

Noise Control (p. 40)

“The placement of tank batteries and other facilities offsite and the use of remote well monitoring systems can reduce vehicle traffic in the field and the associated 

noise.”

Visual/Scenic Resources (p. 41)

“Other considerations in more visually sensitive areas may include ... using...low-profile tanks; avoiding the placement of tanks on the ridgeline....”

.
April 1, 2014 Page 62

Placement of Production Facilities (p. 41)

“Consider centralizing production facilities offsite in an area that is out of important wildlife habitat or is screened from view by vegetation or topography.”

Chapter 6. Reclamation and Abandonment

Reclamation Plan

Pit Reclamation (p. 44)

“All pits must be reclaimed to a safe and stable condition and restored to a condition that blends with the rest of the reclaimed pad area. If it was necessary to line 

the pit with a synthetic liner, the pit must not be breached (cut) or filled (squeezed) while still containing fluids. Pits must be free of oil and other liquid and solid 

wastes prior to filling. Pits may be allowed to air dry or may be solidified in place with BLM or FS approval. The pit liner must be removed to the solids level or 

treated to prevent its reemergence to the surface or its interference with long-term successful revegetation. If necessary, the pit area should usually be mounded 

slightly to allow for settling and positive surface drainage. “

“The concentration of nonexempt hazardous substances in the reserve pit at the time of pit backfilling must not exceed the standards set forth in the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), 42 USC 9605, as amended by the Superfund Amendments and 

Reauthorization Act of 1986 (SARA), PL 99-499. All oil and gas drilling-related CERCLA hazardous substances removed from a location and not reused at another 

drilling location must be disposed of in accordance with applicable Federal and State regulations. {(Refer to 42 USC 9601(14)(Definition of “hazardous 

substances”); 42 USC 6921(2)(A)(exclusion of certain wastes associated with exploration and production); EPA 530-95-003, Crude Oil and Natural Gas 

Exploration and Production Wastes: Exemption from RCRA Subtitle C Regulation (May 1995)}.”

Well Site Reclamation

Final Reclamation (p. 47)

“All excavations and pits must be closed by backfilling when they are dry and free of waste and graded to conform to the surrounding terrain.”

Reclamation of Other Associated Facilities (p. 49)

“Other facilities and areas of surface disturbance associated with Federal oil and gas lease development, including water impoundments, power lines, metering 

buildings, compression facilities, and tank batteries must be removed and reclaimed in accordance with the standards identified previously and with the 

requirements of the surface management agency or surface owner.”
April 1, 2014 Page 63

7. National Park Service (NPS) - Operators Handbook for Nonfederal Oil and Gas Development in Units of the National 

Park System, October 2006

Website: http://www.nature.nps.gov/geology/oil_and_gas/op_handbook.cfm

General Description:

This document developed by NPS provides guidance for nonfederal oil and gas operators in units of the National Park System. It

includes an overview of regulations and voluntary management practices for exploration, development, and production operations on 

NPS lands.

Specific Sections that Concern Pits and/or Tanks:

Chapter 4. Drilling & Production Operations

Table 4.2. Recommended Mitigation Measures for Drilling and Production Operations on NPS Lands (pp. 69, 74-81)

“Table 4.2 lists mitigation measures for drilling and production operations. Use of mitigation measures shown in the table are recommended by the NPS to ensure 

compliance with the NPS approval standard to utilize

“... technologically feasible methods least damaging to the federally owned or controlled lands, waters and resources of the unit while assuring the protection of 

public health and safety” (36 C.F.R. §.9.37(a)(1)). Many of the mitigation measures are derived from environmental guidelines and publications developed by the 

oil and gas industry and environmental professionals and may not address every environmental topic or risk that may be encountered during oil and gas 

operations. These tables are intended to be a tool to be used during project planning. An operator can look through the tables to see which measures would apply 

to an operation and select the most appropriate measures to include in his/her plan. An operator has the discretion to select the most appropriate mitigation to 

meet the NPS least damaging approval standard.” (p. 69)

“When possible, adding fill is preferable to grading and excavation to construct roadways, wellpads, berms, secondary containment, etc. All reasonable attempts 

should be made not to disrupt the hydrology and adjoining wetlands.” (p. 75)

“Construct a berm or ring levee around the drilling location. Install impermeable liners underneath the drilling rig and associated equipment including fuel storage 

and transfer areas. Install the liner to direct fluids to a collection point(s) for recycling or disposal.” (p. 75)

“Use secondary containment (impermeable liner) around fuel, crude, and brine tanks, vessels, and under tank battery load-line connections to collect leaks, drips, 

and spills. Design secondary containment to eliminate or minimize collection of precipitation.” (p. 77)

“Use secondary containment under tank battery load-line connections.” (p. 79)

“Set storage tanks and other equipment on elevated and aerated base to prevent corrosion.” (p. 79)
April 1, 2014 Page 64

“Store NORM-contaminated waste in above ground tanks for proper disposal.” (p. 79)

“Empty storage tanks and fill with water in preparation for flooding or major storm events (i.e., hurricanes).” (p. 79)

Drilling Pad Design

Strategies to Reduce Environmental Risks (p. 86)

“Use impervious liners under all of the rig equipment, mud tanks, pipe racks, and other sources of spills to prevent soil contamination and to provide for effective 

stormwater management.”

“Build a berm and/or ring levee around the entire location to provide backup should a spill escape from the lined area under the rig components. The fill for the pad 

should be relatively impermeable so not much seepage should occur if a spill escapes the lined areas.”

Environmental Precautions During Drilling Operations

Earthen Reserve Pits Versus Steel Tanks (p. 88)

“The NPS no longer allows the use of earthen pits, even lined pits, inside a park. Depending on state requirements, wells drilled from surface locations outside the 

park may use earthen pits provided the operator constructs and maintains the pit to prevent migration of its contents. However, if damage occurs to park resources 

in the event of a spill, the operator will be liable for that damage.”

“Inside a park unit an operator must use a fully containerized, closed-loop drilling fluid system in place of an earthen reserve pit system. This technique drastically 

reduces the potential for soil and water contamination. The closed-loop system usually needs less area than an average reserve pit so the operator can reduce the 

overall drill site area and area of potential impact.”

“This earthen reserve pit would no longer be appropriate for operations inside a park. Pits create more surface disturbance and are more likely to leak 

contaminants to the environment.”

“Steel tanks that hold water, reserve mud, and cuttings replace the need for traditional earthen reserve pits.”

Well Cuttings and Mud Disposal (p. 89)

“Use an efficient mud cleaning system and catch cuttings in steel tanks.”

Well Servicing and Workover Operations

Strategies for Clean Well Servicing and Workover Operations (p. 93)
April 1, 2014 Page 65

“Use a synthetic liner and board matting under rig components and construct berms/trenches to direct liquids to cellar.”

“Use steel tanks to hold workover fluids and all liquids and solids returned from the well until they can be removed from the site.”

“A small pump can be used to move liquids that might accumulate in the cellar to appropriate tanks or containers for reuse or disposal.”

Berm Design and Construction (p. 96)

“Berms should be constructed with materials sufficiently impervious to contain spills.”

“Berms should be designed and constructed with sufficient perimeter and height to hold 1.5 times the volume of the largest tank.”

“Containment systems constructed with corrugated galvanized steel are commercially available as an alternative to earthen dikes.”

Tanker Truck Loading (p. 97)

“Loading box located inside the tank’s bermed, lined area adds another level of protection.”

Chemical Handling

Strategies for Sound Chemical Handling (pp. 100-101)

“Use secondary containment under chemical drums and bulk containers.”

“A bulk storage tank and the chemical injection pump, a common source of leaks and drips, are mounted over secondary containment.”

“The operator in this photo uses bulk chemical storage and places them inside the storage tank’s lined and bermed area.”

Chapter 5. Directionally Drilling a Well from Outside Park Boundaries to Inside a Park Unit

Table 5.1. Suggested Mitigation Measures to Minimize Potential Threats to Park Resources and Values from Directional Drilling

Operations Outside a NPS Unit (p. 118)

“Use closed loop containerized mud system or lined reserve pits.”

“Use secondary containment around fuel, crude, and brine tanks and vessels.”

“Fence and net open pits if they attract wildlife.”
April 1, 2014 Page 66

National Park Service Well Plugging Guide for Nonfederal Oil and Gas Wells (p. 145)

“All fluids and solids returned to the surface from the wellbore should be collected in metal tanks and disposed of at an approved disposal site outside of the park.”

Table 7.2. Well Plugging and Surface Reclamation Recommended Mitigation Measures (p. 171-173)

“Collect all fluids and solids returned to the surface from the wellbore in metal tanks and dispose of them in an approved disposal facility outside of the park.”

“To ensure successful reclamation of the site, an operator should:....

• Properly design and construct berms and liners to guard against contamination of the site. In a park, the mud system would have been a closed loop 

containerized mud system instead of earthen pits.”

Site Reclamation (p. 174)

“Dewater pit contents (this would only apply to operations outside of a park).”
April 1, 2014 Page 67

8. Earthworks - Oil & Gas Accountability Project (OGAP) - Best Practices

Website: http://www.earthworksaction.org/ogapbestprac.cfm

General Description:

This web-based document presents compiled information regarding various recommended practices that can be used with the goal of 

minimizing impacts during oil and gas operations. 

Specific Sections that Concern Pits and/or Tanks:

Best Practices Overview

http://www.earthworksaction.org/issues/detail/best_practices_overview

“There are better, cleaner, more efficient ways to extract and produce oil and gas.

In some cases these "best" practices are developed and used by companies to save money.

In other cases alternative practices, or best management practices (BMPs), are required by regulatory requirement.”

Voluntary Best Practices

“Some oil and gas companies innovate and improve their systems to cut costs. By cutting air emissions, reducing water use, controlling erosion, and 

employing other practices that increase revenue, they also reduce impacts on communities and the environment.

Closed loop/pitless waste disposal

For example, technologies have been developed that allow oil and gas operators to forego digging earthen waste pits. Instead, they used “close loop” 

systems where wastes enter steel tanks. For more information on this process and the benefits and profits that it brings to the industry, see Alternatives to 

Pits.

Natural Gas STAR

Through Natural Gas STAR, a voluntary EPA program, participating companies implement approximately 150 cost-effective technologies and practices that 

reduce emissions of air pollution from oil and gas development. In the process, they reduced emissions by 114 billion cubic feet (bcf) in 2008.

By capturing and selling gas that would have otherwise leaked into the atmosphere, U.S. companies gained revenue of more than $802 million.”
April 1, 2014 Page 68

Required Best Practices

“Oil and gas production regulations vary in stringency from state to state. If states with the most rigorous (in terms of protecting communities and the 

environment) rules – the “best practices” -- still have an active oil and gas industry, it demonstrates that companies can be better actors and still be 

competitive.

When these best practices are first codified industry will often challenge the new rules. They invariably argue that the cost of implementing the best practices 

will force them to go elsewhere.”

Colorado’s Pit Rule

“This happened in 2008 when the Colorado Oil and Gas Conservation Commission updated its rules.

One update required the disposal of pit liners in accordance with solid waste regulations -- using certified landfills or recycling them. Previously, operators 

were allowed to bury potentially toxic pit liners at the drilling site.

The Colorado Petroleum Association initially objected to the rule, but ultimately reconsidered. Meanwhile, one company, Williams, developed innovative ways 

to work with the rule – by “turning the waste into a resource.” Williams bales the liner and sells them to industries that recycle them into non-food-grade 

industrial products like bumpers or pallets; and by circumventing the need for drilling pit liners by switching to closed loop drilling systems.”

For more information:

“Earthworks has compiled information regarding various best, better or alternative practices that can be used to minimize impacts during oil and gas 

operations.

• Alternatives to pits

• Closed-loop drilling systems

• Directional drilling

• Flareless (green) completions

• Minimizing waste

• Surface disturbance

• Visual impacts

• Noise

• Air pollution
April 1, 2014 Page 69

Other resources:

Oil and Gas BMPs - general

• Intermountain Oil and Gas Best Management Practices (BMP) Project. The Natural Resources Law Center at the University of Colorado has 

developed a “searchable BMP database” that has examples of voluntary and required best practices in the Intermountain West (Colorado, 

Wyoming, Montana, Utah and New Mexico).

• The federal Bureau of Land Management has compiled BMPs for road construction, visual resource management, wildlife, air resources, and 

general oil and gas operations.

• The Western Governor's Association has developed a handbook of Best Management Practices for Coalbed Methane Development.

Surface Owner and Wildlife Protections

• Doing it Right: Best Oil and Gas Development Practices for New Mexico. This EARTHWORKS fact sheet includes a framework for protecting 

surface owner rights, soil air and water, and wildlife habitat; and responsible energy development in New Mexico.

• Drill-Right Texas. This EARTHWORKS publication provides a reasonable and planned approach to reduce the long-term impacts of oil and gas 

development in Texas.

• Doing it Right - Protecting our water, farms and ranches, and communities from irresponsible coal bed methane development. This guide, 

written by Northern Plains Resource Council, outlines a strategy for ensuring that coal bed methane is developed responsibly in Montana.

• ALL Consulting. 2002. Handbook on Best Management Practices and Mitigation Strategies for Coal Bed Methane in the Montana Portion of the 

Powder River Basin.

Other

• Colorado Oil and Gas Conservation Commission's Outstanding Oil and Gas Operation Awards may give landowners a sense of what some 

companies have done to set them apart from the rest of the industry.

• Petroleum Technology Transfer Center (PTTC) - Environmental and Water Case Studies.”

Alternatives to Pits

http://www.earthworksaction.org/index.php/issues/detail/alternatives_to_pits

Closed containment systems

“Pits are used to store oil and gas wastes such as produced water, fracking flowback and other liquids not captured for sale during oil and gas production. There 

are many potential problems from pits -- leaky liners and overflows can lead to soil and water contamination, pits can produce odors and toxic air contaminants, 

and pits can be a hazard for birds and wildlife.
April 1, 2014 Page 70

If pits are used to store oil and gas wastes, they should have, at minimum:

• two layers of liners,

• a leak detection system between the liner layers,

• fences tall and strong enough to keep out wildlife, and

• nets or other devices installed to prevent birds from coming in contact with the wastes.

Pits aren't necessary

There are more environmentally friendly alternatives to using pits (even lined pits):

• Closed containment systems (tanks)

• Closed-loop drilling systems

• Closed-loop drilling case studies”

Closed Containment Systems

http://www.earthworksaction.org/index.php/issues/detail/alternatives_to_pits#TANKS

“Oil and gas operators can use closed containment systems (e.g., tanks that are not open on top) in place of various production pits.

As with pits, it is important that tanks be enclosed by fences and nets. Otherwise, birds, wildlife and livestock may still be attracted to the liquid in the tanks.

Tanks have a tendency to corrode with time and develop leaks. And they may overflow if their capacity is not adequate to hold the wastes (and any precipitation if 

the tanks are not enclosed).

The New Mexico Oil and Conservation Division's document Pollution Prevention Best Management Practices for the New Mexico Oil and Gas Industry suggests 

the following measures to prevent contamination from tanks. [1]

• All above ground tanks that contain fluids other than fresh water must be contained in an impermeable bermed enclosure to contain a volume of one-third 

more than the total volume of the largest tank or of all interconnected tanks.

• All below grade tanks. . . must have secondary containment and leak detection.

The photo of the system above (credited to USFWS) does not have adequate secondary containment. If a leak were to develop underground the wastes would 

seep into the soil, contaminating the soil and possibly the groundwater. The lid does adequately prevent wildlife and birds from accessing the wastes. The pipe 

coming out of the lid allows venting of any built-up gases in order to prevent explosions.
April 1, 2014 Page 71

The tank in the photo to the right has a steel-mesh lid to keep out wildlife and birds. The secondary containment pit has prevented the fluids from flowing all over 

the well site, but the waste fluids have seeped into the surrounding soil. Thus, it is possible that groundwater contamination has occurred. These wastes, which 

may contain toxic chemicals, are now accessible to wildlife.

Benefits of closed containment systems

• Tanks require little or no maintenance.

• Tanks may be reused (moved to a new site) when the well stops producing.

• Tanks isolate waste products from the environment; if enclosed tanks are installed, there is no need to install fences or netting to keep out wildlife and

livestock.

These systems greatly reduce or eliminate soil contamination, thereby reducing remediation costs.

Examples of closed containment systems:

• In 2003, the Farmington, New Mexico City Council approved five gas wells on the condition that the company agreed to store condensate wastes in 

buried tanks; and install double walled condensate tanks as a means of leak protection.(Source: Laura Banish. February 12, 2003. "Farmington council 

approves five new gas wells," Farmington Daily Times).

• Many well sites in New Mexico use tanks to hold production wastes, but most lack leak detection devices and adequate secondary containment systems.

In the photo to the right, the tank has a solid top to prevent wildlife access. But there is no secondary containment system to prevent any fluids that overflow from 

seeping into the soil, and there is no way to easily detect if the bottom of the tank is leaking.”

Closed-loop or “pitless” drilling systems

http://www.earthworksaction.org/index.php/issues/detail/alternatives_to_pits#CLOSEDLOOP

“During drilling operations, "closed-loop" drilling fluid systems (sometimes referred to as "closed mud" or "pitless" systems) can greatly reduce or eliminate the 

discharge of toxic drilling wastes on site. These systems negate the need for drilling reserve pits. Not only is it possible to have pitless drilling operations, it can 

also be an economic advantage to companies to used closed-loop drilling systems.

Many companies are using closed loop drilling systems in Texas, Louisiana, Oklahoma, Alaska and other states. Examples of companies who are using closedloop technologies include: Shell, El Paso, Chevron-Texaco, Exxon, and many others.

Differences between conventional drilling and closed-loop drilling systems

At a typical oil or gas drilling site, drilling fluids (mud, water, additives) are circulated through the wellbore, then the fluids and drill cuttings (rock fragments created 

by the drilling process) are deposited in a reserve pit dug near well. This pit is used to hold used drilling fluids and wastes.

A reserve pit can be the source of considerable costs at a drilling site.
April 1, 2014 Page 72

• The pit itself must be constructed at the beginning of drilling, which requires the use of heavy earthmoving equipment.

• The pit may have to be lined.

• When the drilling project is over, the pit, including all of the waste fluids and solids, must be properly remediated. Remediation could include activities 

such as: the removal and offsite disposal of the waste materials and liner; the burial of the wastes and liner; backfilling of the pit with soil; and 

revegetation of the disturbed pit area.

Also, there are health, environmental, and financial risks associated with pits, which can contaminate soils with hydrocarbons, metals and salts, and leak 

potentially toxic liquids into surface or groundwater. [2]

In a closed-loop drilling fluid system, the reserve pit is replaced with a series of storage tanks that separate liquids and solids. Equipment to separate out solids 

(e.g., screen shakers, hydrocyclones, centrifuges) and collection equipment (e.g., vacuum trucks, shale barges) minimize the amount of drilling waste muds and 

cuttings that require disposal, and maximize the amount of drilling fluid recycled and reused in the drilling process. The wastes created are typically transferred offsite for disposal at injection wells or oilfield waste disposal facilities.

The tanks represent an additional cost, but overall, pitless drilling can save an operator money because there is no need to construct a pit, there is a reduction in 

the amount of environmental releases, and the closed-loop system results in more efficient use of drilling fluid.”

“Benefits of Pitless Drilling:[3]

• it eliminates unsightly and hazardous pits

• it reduces the time, energy and expense of building, fencing and reclaiming reserve pits

• it decreases the need for cuts in sensitive and hilly areas

• total surface disturbance associated with a well pad is reduced

• it eliminates risk of waterfowl and wildlife mortality related to pits

• it eliminates risk of damaging underground pipelines and utilities

• it allows drilling in areas with a high ground water table

• it virtually eliminates drilling waste

• rigs use less water per well - it can reduce water consumption by as much as 80%

• the US Environmental Protection Agency (EPA) has estimated that "closed loop systems" can reduce the volume of drilling fluids by as much as 90% [4]

• it eliminates soil segregation, which reduces wind erosion problems

• it reduces truck traffic associated with transporting drilling wastes by as much as 75%

• it may improve relationship with surface owners

• it greatly reduced waste tracking and need for land farming operations

• drill cuttings may be put to beneficial use, e.g., if not contaminated they may provide a source of finely-ground clay for berm construction around tank 

batteries or other uses

• the tanks can be re-used”
April 1, 2014 Page 73

Closed-loop systems reduce company liability

“Pits may or may not be lined (depending on the oil and gas regulations); and pits are open to the atmosphere. Because of this, the pit may leak liquids into 

surface or groundwater and release high levels of volatile organic compounds, which in turn create health, environmental, and financial risks. If improperly fenced, 

livestock may enter the pit area. If the livestock is poisoned by the pit materials, companies may be liable for the deaths, and be required to compensate the 

livestock owner.

According to the Railroad Commission of Texas, even though closed-loop drilling is not always the least expensive option, some companies in Texas have elected 

to use only closed-loop drilling fluids systems in their operations. Why? Because whenever a closed-loop system is used, the operator reduces the potential future 

liability associated with a conventional earthen pit, and reduces the waste management and site closure costs. It's also good for the company image and public 

relations.”

Increased Utilization of Closed-Loop Drilling

“According to a paper entitled "Bulk Transportation of Drilling Wastes," delivered at an American Association of Drilling Engineers Conference in 2002:

. . .environmental concerns and regulatory authorities are forcing the offshore drilling industry to modify or eliminate dumping of drilling wastes overboard. 

On land rigs, the practice of constructing earthen reserve pits is also declining in favor of 'zero-discharge' closed-loop systems. Therefore the effective 

containment and transportation of drilling wastes is becoming ever more important. The environmental benefits of a well designed waste collection and 

transportation system can be observed directly in many cases.[5]

The New Mexico Oil Conservation Division identifies closed-loop drilling as a "best management practice" in their Pollution Prevention Best Management Practices 

for the New Mexico Oil and Gas Industry. (See footnote 1) New Mexico OCD is not alone in identifying closed-loop drilling systems as a best practice. In almost 

any pollution prevention or "Best Management Practices" document for the oil and gas industry, closed-loop drilling systems are mentioned as the most 

environmentally safe method for reducing the potential impact that drilling operations can have on the environment. For example, the practice is mentioned in the 

following documents:

• The Illinois Environmental Protection Agency's Best Management Practices for Oil Exploration and Extraction

• Railroad Commission of Texas' Waste Minimization in Drilling Operations

Increasingly, closed loop systems are being used all over the United States, Canada, and the world. In personal conversations with closed-loop drilling system 

companies, OGAP has heard that one company has performed approximately 900 closed-loop drilling operations in the past eight years (in CO, WY, ND, NM and 

other western states). A representative from another company operating out of Texas, Louisiana and Oklahoma remarked that most of the major companies in the 

region are using closed-loop drilling systems at the majority of their operations, because they understand the potential future liabilities that may follow them if they 

use conventional drilling systems that use reserve pits.

This information was corroborated by the Texas Railroad Commission, which stated that, "Even though it is not always cost effective, some companies have 

elected to use only closed loop drilling fluid systems in their operations. . .whenever a closed-loop system is used, the operator reduced his potential liability 

associated with a conventional earthen pit and waste management and site closure costs." [6]
April 1, 2014 Page 74

According to the U.S. Congress, Office of Technology Assessment, these systems are increasingly being used (e.g., in California) because of the reduction in 

overall drilling costs and in the volume of wastes needing disposal. (See footnote 4)”

Comparison of closed-loop systems versus pits

“CASE 1: Prima Energy's Cost-Benefit Analysis [7]

Prima Energy Corp. has drilled more than 68 wells in Colorado using a highly automated closed-loop system, which the company started developing along with 

Nabors Drilling USA, Inc. in 1993. The company found that the economics of drilling these wells in Colorado were best if drilling required less than 12 days.

The table below provides a summary of the economics of using conventional reserve pits versus closed-loop drilling systems.

* Dewatering cost includes rental of unit, labor, extra fuel, polymer and acid,

linear motion shaker, centrifuge, trucking, end loader and miscellaneous costs.

Prima Energy's calculated benefits of closed-loop drilling:

• cost savings of $1,320 per well

• water savings of 5,200 barrels (closed-loop drilling used 80% less water)

CASE 2: MiSWACO - Closed-loop vs. Conventional Systems: A tale of two wells [8]

Closed-loop systems employ a suite of solids control equipment to minimize drilling fluid dilution and provide the economic handling of the drilling wastes. For one 

company, a typical closed-loop system includes a series of linear-motion shakers, mud cleaners and centrifuges followed by a dewatering system. The 

combination of equipment typically results in a "dry" location where a reserve pit is not required, used fluids are recycled, and solid wastes can be landfarmed, 

hauled off or injected downhole.

Two wells, drilled only 200 ft apart in Matagorda County, TX, provided a unique opportunity to compare the cost savings difference between conventional solidscontrol equipment and the company's closed-loop system. Both wells drilled through the same formations, using the same rig crew, mud company and bit

program.
April 1, 2014 Page 75

The closed-loop system with improved solids control resulted in some significant savings:

• 43% savings in drilling fluid costs

• 23% fewer rotating hours

• 33% fewer days to drill to a comparable depth

• 37% reduction in the number of bits used

• up to 39% improvement in the rate of penetration

CASE 3: Reducing Waste Volume and Costs Using Closed-loop Systems [9]

Challenges: Challenges associated with conventional reserve pits include volume of drilling wastes; drill site installation and restoration costs; pollution of land 

and/or surface water due to failure of pits and/or containment system and associated cleanup costs; and potential for subsurface pollution due to downward 

migration from pits and/or surface soil permeability.

Solution: Use closed-drilling pit system to reduce volume of drilling waste. The drilling contractor maintained "safe pit levels" and recycled drilling fluid to minimize 

pit volumes and disposal requirements. Waste management costs due to procedures other than those specified were also the responsibility of the drilling 

contractor. Cost savings provided the incentive to implement and maintain proper procedures to minimize waste generation in the closed-loop system.

Conventional reserve pit Closed-loop drilling

fluid system

Surface disturbance

reserve pit (235' x 77' x 5')

cuttings pit (20' x 10' x 5')

water pit (40' x 10' x 5')

No reserve pit necessary.

Total drilling mud and wastes

in pits 16,625 barrels 1,100 barrels

Total reduction in drilling mud and wastes in pits using closed-loop drilling 15,625 barrels
April 1, 2014 Page 76

Benefits: The following benefits were realized:

• Total estimated cost savings (considering reduced costs for drill site installation, fluid hauling and disposal, dirt work, and surface damage payment): 

$11,000.00

• Reduced surface disturbance by 18,000 square feet (0.4 acres).

• Reduced drilling mud and wastes in pits by 15,625 barrels.

• Reduced potential for environmental impact to surface and groundwater.

CASE 4: Closed Loop Drilling Fluid System [10]

Problem: A small independent operator was concerned about the volume of drilling waste in conventional reserve pits at his drilling locations. Waste management 

costs were a concern, as well as the costs associated with impact on adjacent land due to pit failures. The operator was concerned about the potential for surface 

water or ground water contamination and the associated potential liabilities.

Solution: The operator was drilling relatively shallow wells in normally pressured strata. Because the drilling plan was relatively simple, the operator investigated 

the feasibility of using a closed-loop drilling fluid system for these wells. The use of a closed-loop system eliminated the need for a conventional reserve pit. The 

operator negotiated with drilling contractors to obtain a turn-key contract that required the drilling company to use a closed-loop system and take responsibility for 

recycling the waste drilling fluid.

Benefits: The turn-key contract was incrementally more expensive. Yet, because of reduced drill site construction and closure costs; reduced waste management 

costs; and reduced surface damage payments, the operator realized a savings of about $10,000 per well. Also, the operator reduced the potential for 

environmental impact and associated potential liability concerns.

CASE 5: Closed-loop System Helps Reduce Drilling Waste [11]

A large oil and gas production company used a number of pollution prevention techniques, including closed loop drilling, to drill an exploratory well adjacent to the 

Tishomingo Wildlife Refuge in Johnston County, OK. The well was drilled on land owned by the U.S. Army Corps of Engineers. Some of the measures taken in 

drilling the well included:

• Using a closed-loop mud system that allowed for reuse of drilling fluids and use of smaller quantities of water for dilution of the mud to control viscosity 

and density

• Use of compressed air as the drilling fluid where possible, which allowed for the use of smaller quantities of water and drilling fluid

• Using a smaller casing, which allowed for the use of a 25% smaller hole. This generated a smaller volume of drill cuttings and required less drilling fluid

Savings and Benefits: The hole-size reduction, use of air drilling and closed-loop system reduced wastes by close to 1.5 million pounds. A material and disposal 

cost savings of $12,700 was achieved.

For more information:
April 1, 2014 Page 77

Sources:

1. New Mexico Oil Conservation Division (OCD). Pollution Prevention Best Management Practices for the New Mexico Oil and Gas Industry. Volume I, 

Section 6, pp. 49, 50. Available for download from the OCD web site.

2. U.S. Environmental Protection Agency (U.S. EPA). October, 2000. Profile of the Oil and Gas Extraction Industry. EPA Office of Compliance Sector 

Notebook Project. EPA/310-R-99-006. p.69.

3. Longwell, John. Prima Energy Corp; and Glenn Hertzler, Nabors Drilling USA, Inc. "Closedloop system as a cost effective alternative to reserve pits." 

Presentation to the Consortium for Emerging Gas Resources in the Greater Green River Basin, Advances in Drilling Technologies for the North American 

Rockies (Denver, Colorado, April 28, 1997).

4. U.S. Congress, Office of Technology Assessment. March, 1992. Managing Industrial Solid Wastes from Manufacturing, Mining, Oil and Gas Production, 

and Utility Coal Combustion. Background Paper, OTA-BPO-82. (Washington, DC: U.S. Gov. Printing Office). p. 75

5. Richards, M.J. and Love, W.W. 2002. "Bulk Transportation of Drilling Waste," a paper presented at the American Association of Drilling Engineers 2002 

Technology Conference, April 2002, in Houston, TX. Paper AADE-O2-DFWM-HO-18.

6. Railroad Commission of Texas. Oil and Gas Division. Waste Minimization in Drilling Operations.

7. Longwell, John and Hertzler, Glenn. (Prima Energy Corp. and Nabors Drilling USA, Inc., respectively). 1997. "Closed-loop system as a cost effective 

alternative to reserve pits," presented at the Advances in Drilling Technologies for the North American Rockies Conference (April 28, 1997, Denver, CO); 

and Interstate Oil and Gas Conservation Commission. 1999 Chairman's Stewardship Award Report.

8. M-I SWACO. "Swaco closed loop systems: A tale of two wells." This is Swaco. p. 3

9. New Mexico Oil Conservation Division (OCD). Pollution Prevention Best Management Practices for the New Mexico Oil and Gas Industry. Available for 

download from the OCD web site.

10. Railroad Commission of Texas. Waste Minimization - Case Histories - Drilling Operations.

11. Oklahoma Department of Environmental Quality. Pollution Prevention Case Studies.

Other Sources

• Earthworks: General information on oil and gas industry pit pollution

• New Mexico groundwater contamination from oil and gas facilities and pits”

Flareless “Green” Completions

http://www.earthworksaction.org/index.php/issues/detail/flareless_completions

“Flareless or "green" completions reduce flaring and venting of natural gas. Before natural gas and coalbed methane wells begin producing gas for sale, the well 

bore and surrounding reservoir must be "cleaned up" (i.e., any fluids, sand, coal particles, or drill cuttings within the well bore must be removed). The 

conventional method for doing this is to pump air down the well bore, which lifts the waste fluids and solids out. The solid and liquid waste materials are then 

dumped into a pit or tank, and any gas that is removed is flared or vented to the atmosphere. In some flareless or green completions, natural gas, rather than air, is 

pumped down the well bore to clean it out.[1]

In flareless or green completions the gas that comes to the surface is separated from fluids and solids using a series of heavy-duty separators (sometimes referred 

to as "flowback units"). The water is discharged to tanks to be reused, the sand is sent to a reserve pit, and the gas is either cycled back through the well bore, or 

sent to a pipeline to be sold rather than vented or flared. According to the U.S. Environmental Protection Agency (EPA), benefits of this system include: the 
April 1, 2014 Page 78

elimination or reduction in venting or flaring of natural gas; sale of the gas and condensate provides the operator with an immediate revenue stream; there is a 

reduction in solid waste and water pollution; and the system enables safer operating practices.

Emissions Reductions: One company, which drilled 63 wells using flareless completions, reported a reduction in natural gas emissions of 7,410 thousand cubic 

feet per year, which is 70% of the gas that would formerly have been vented to the atmosphere. [2] Another company has been able to reduce flaring by 85-

90%.[3]

Costs and Pay-Back: The capital costs for companies include the use of separators, sand traps and tanks. One company reported these costs as being $180,000. 

The equipment, however, can be moved from site to site, so if a company were to complete 60 wells per year the annual capital charges would be less than 

$10,000. Operating costs are less than $1,000 per year. EPA has estimated that "green completions" can pay back their costs in about 1 year.

An alternative to sending the gas to the pipeline is to send it to a flare tank. Flare tanks capture and more fully combust the waste gases. The tanks can be carried 

from site to site. This practice avoids the costs associated with excavating and reclaiming flare pits, and avoids the potential liability associated with cleaning up 

soils contaminated by flaring.

For more information:

Sources:

[1]D'Ambrosio, D. July 14, 2004. "BP experiments with flareless wells in county," Durango Herald.

[2] U.S. Environmental Protection Agency. 2004. "Green Completions." EPA Partner Reported Opportunities for Reducing Methane Emissions, PRO Fact Sheet 

No. 703.

[3]Williams Production RMT Company - Parachute office (a subsidiary of Williams Energy Services).”

Minimizing Surface Disturbance

http://www.earthworksaction.org/index.php/issues/detail/minimizing_surface_disturbance

“Well pads are often much larger than they need to be - sometimes exceeding several acres in size. At Ted Turner's Vermejo Park Ranch, however, the well pads 

are only 0.6 acres. (See Vermejo Park Ranch Coal Bed Methane Project Mineral Extraction Agreement Summary, in Oil and Gas at Your Door - a Landowner's 

Guide to Oil and Gas Development, Chapter III).

After the drilling phase if over, the portion of the drilling pad not needed for oil or gas production can be reclaimed. This is known as interim reclamation, and it is 

required by law in many states. Unfortunately, lack of enforcement by state agencies means that interim reclamation does not occur in many jurisdictions.

During the drilling phase, pad size can be reduced by drilling multiple wells from one site. For example, at the Vermejo Park Ranch two or more wells have been 

drilled from the same pad (see directional drilling).
April 1, 2014 Page 79

Redesigning pits can decrease the amount of surface disturbance.

If a pitless drilling system is not used for drilling fluids, another approach may be to use a V-shaped pit instead of the traditional rectangular pit. This type of pit 

reduces water requirements, as well as the amount of surface disturbance.

The design is as follows: the open end of the "V" faces the drilling rig and the cross-sectional view resembles a squared-off funnel (about 10 feet deep with the 

upper 5 feet having slanted walls to a width of about 20 feet). Because the fluid must travel the full length of the pit, this design prevents mud from channeling 

between the discharge point and the suction point, and reduces the amount of water that must be added to maintain the desired fluid characteristics. In addition, 

because the V-shaped pit is long and narrow, it is easier to construct and leaves a smaller "footprint" at the site.[1]

A company installed a V-shaped reserve pit and compared the costs with those incurred at similar-sized wells using a traditional pit. The company determined that 

pit construction time was reduced by about 40 percent, water costs for the well were reduced by about 38 percent, and pit liner costs were reduced by about 43 

percent. The total cost savings were about $10,800 per well.

It should be noted that whenever earthen pits are used to store wastes, they should be lined with multiple layers of synthetic fabric with leak detection devices 

between the layers.

For more information:

Sources:

1. Railroad Commission of Texas, Oil and Gas Division. Waste Minimization in the Oil Field. Chapter 5. Page 5-3.”
April 1, 2014 Page 80

9. Houston Advanced Research Center - Environmentally Friendly Drilling Systems Program (EFD) - Hydraulic 

Fracturing BMPs

Website: http://efdsystems.org/index.php/best-management-practices

General Description:

This national website directory contains EFD research information and publications on voluntary management practices. The program 

is operated by Houston Advanced Research Center and Texas A&M University, with the support of industry, environmental 

organizations, academia, and government agencies. The stated goal of the program is to “integrate advanced technologies into 

systems that significantly reduce the impact of petroleum drilling and production in environmentally sensitive areas.” A presentation 

on the EFD program was given to the SEAB Shale Gas Production Subcommittee.10

Specific Sections that Concern Pits, Tanks, and/or Land Application:

- Search directory for information on voluntary management practices.

 10 Dr. Richard Haut, Houston Advanced Research Center, Environmentally Friendly Drilling Systems Program, Presentation to the Secretary of Energy Advisory 

Board Shale Gas Production Subcommittee, June 28, 2011, http://www.shalegas.energy.gov/resources/062811_efd_presentation.pdf
April 1, 2014 Page 81

10. Oklahoma Corporation Commission - Pollution Prevention at Exploration and Production Sites in Oklahoma: BMPs for 

Prevention and Control of Erosion and Pollution, Water Quality Series E-940, April 2002

Website: http://www.occeweb.com/og/E-940.pdf

General Description:

This document presents voluntary management practices for use at typical exploration and production sites in Oklahoma.

Specific Sections that Concern Pits and/or Tanks:

Drilling and Production Sites (p. 33)

“Erosion control and prevention of water contamination should be considered when planning, constructing, and operating oil and gas facilities. Roads, pads, pits, 

and tank batteries should be constructed, maintained, and closed according to OCC rules.”

Containment for Tank Batteries and Pits (pp. 33-34)

“Dikes should be constructed around storage tanks for spill containment (Figure 9).”

“The diked area should be large enough to contain at least the volume of the largest tank in the facility. A splash pad/apron should be constructed at the unloading 

area of any disposal well pit. Follow all applicable regulations concerning site facilities and containment for tank batteries and pits.”

Drillsite Pits and Disposal of Drilling Mud (p. 35)

“Reserve mud pits and completion/fracture/workover pits must be constructed and lined according to OCC rules. At least 24 inches of freeboard must be 

maintained at all times to prevent overflow and the release of drilling mud or other fluids.”

Closure of Pits (p. 36)

“Pits must be properly closed to prevent pollution of surface water or ground water, and/or danger to wildlife. This means taking extreme care to assure that pit 

contents don’t escape.”

“If the pit contents are to be consolidated in place, the pit must be completely dewatered before trenching, stirring, or otherwise disturbing the bottom of the pit. 

Trenching or stirring is prohibited for certain categories of pits.”
April 1, 2014 Page 82

“A minimum of three feet of soil cover must be applied over any remaining pit contents. Stockpiled topsoil should be applied last. The soil should be mounded and 

shaped to ensure runoff without erosion. Vegetation should be planted and diversion terraces constructed, if necessary (Figure 10).”

“Figure 10. The soil cover on a pit should be mounded and vegetated to shed water.”

Response to Salt Water Spills (pp. 37-38)

“Contain the spill and prevent further discharge. Minimize the area affected by diking or containing the spill in emergency pits, leak-proof tanks, or other suitable 

methods.”

“Salt water spills to surface water must also be corrected immediately. Confine the spill to the smallest area possible by using temporary dikes and emergency 

pits.”
April 1, 2014 Page 83

11. New Mexico Energy, Minerals, and Natural Resources Department - Pollution Prevention Best Management Practices 

for the New Mexico Oil and Gas Industry, 2000

Website: http://www.emnrd.state.nm.us/ocd/documents/2000PollutionPreventionBMPs.pdf

General Description:

This document provides tools for developing an environmental management system for the oil and gas industry in New Mexico. It 

includes a pocket guide that can be used in the field quickly.

Specific Sections that Concern Pits and/or Tanks:

Volume 1

3.0. Systems Approach to Pollution Prevention and Energy Efficiency (pp. 12-13)

“Figure 3-3. Activity-Based Costing Analysis of Produced Water Management”

4.0. Case Studies and the Effective Use of the Systems Approach for the Oil and Gas Industry

Case History 1 - Drilling Operations

Use of “Closed Drilling Pit System” to Reduce Drilling Waste (pp. 23-24)

“CHALLENGE — Challenges associated with conventional reserve pits include volume of drilling wastes; drill site installation and restoration costs; pollution of 

land and/or surface water due to failure of pits and/or containment system and associated cleanup costs; and potential for subsurface pollution due to downward 

migration from pits and/or surface soil permeability.”

“SOLUTION — Use closed-drilling pit system to reduce volume of drilling waste, as follows...”

“The drilling contractor maintained “safe pit levels” and recycled drilling fluid to minimize pit volumes and disposal requirements. Waste management costs due to 

procedures other than those specified were also the responsibility of the drilling contractor. Cost savings provided the incentive to implement and maintain proper 

procedures to minimize waste generation in the closed-loop system.

(Note: Optimum use is for on-shore, normal pressure, relatively shallow drilling operations.)”

Case History 2 – Reserve Pit Management Systems (pp. 25-26)

“CHALLENGE — Using conventional reserve pits, high volumes of drilling wastes that require relatively high management costs are mixed with wastes that have 

relatively low management costs.”
April 1, 2014 Page 84

“SOLUTION — The reserve pit management system was selected to replace the conventional reserve pit. The reserve pit management system uses a set of at 

least four separate pits constructed in an area that would otherwise be occupied by a conventional reserve pit. A separate pit is constructed for at least each of the 

following discharges: 1) shaker solids, 2) settling, 3) storage, and 4) emergency. Space for a dragline is allowed to facilitate the movement of solids from one pit to 

another.”

“BENEFITS — The reserve pit management system offers advantages such as the following:

- Wastes (such as salt cuttings, unexpected saltwater flows, and muds with high barium concentrations) are kept separate from the normal, uncontaminated drilling 

waste, thus minimizing the volume of contaminated waste to be handled.

- Solids (such as contaminated drill cuttings) may be removed from the pits for appropriate management during drilling operations.

- Rainwater can be collected and discharged with minimal treatment when kept separate from contaminants.

- Water from the segregated pits is available for use as makeup water in the mud system, resulting in cost savings.

- Site remediation costs and the potential for long-term liability are minimized.”

6.0. Traditional and Discrete Recommended Best Management Practices (pp. 49-50)

“These best management practices should be used as guidance in considering alternatives in the company’s comprehensive pollution prevention environmental 

management system...”

“2. Drum and Saddle Tank Storage: All drums and saddle tanks containing materials other than fresh water or fluids that are gasses at atmospheric temperature 

and pressure must be stored on an impermeable pad with curbing...”

“4. Above Ground Tanks: All above ground tanks which contain fluids other than fresh water must be contained in an

impermeable bermed enclosure to contain a volume of one-third more than the total volume of the largest tank or of all interconnected tanks.”

“5. Below Grade Tanks/Sumps: All below grade tanks, sumps, and pits must have secondary containment and leak detection.”

7.0. Oil and Gas Exploration and Production

Table 7-2. Drilling Rig Operations Alternatives (p. 57)

“Mud and Additives” 

- “Use a closed-loop mud system. (See Section 4.0, Case History 1).”

- “Use the reserve pit management system. (See Section 4.0, Case History 2.)”

“Produced Water”

- “Use a closed-loop drilling fluid system. (See Section 4.0, Case History 1)”

- “Hydrotest pipelines, equipment, and tanks with produced water.”

Table 7-5. Storage and Transportation Alternatives (p. 62)
April 1, 2014 Page 85

“Produced Water”

- “Use a closed-loop drilling fluid system. (See Section 4.0, Case History 1)”

“Oil-contaminates Soil”

- “Develop procedures to prevent contamination of soils; include preventative maintenance on flow lines and primary and secondary containment under 

tank battery load-line connections.”

- “Use summary or secondary containment under tanks.”

10.0. Oil Field Services

Table 10-1. Well Servicing and Workover Alternatives (p. 76)

“Produced Water”

- “Recycle water in hydrotesting of pipeline, equipment, and tanks.”

“Muds”

- “Use a closed-loop mud system whenever possible to reduce volumes of drilling fluid wastes.”

Volume 2 

3.0. Waste Management Table: Alternatives for Wastes Generated in Oil & Gas Operations

Waste: “Chemicals, surplus or unusable” (p. 29)

Alternatives: “Do not dispose of chemicals in mud or workover pits.” 

Waste: “Drilling fluids and additives, used” (p. 33)

Alternatives - Source Reduction: “Use solids control technology (e.g., chemically enhanced centrifuge) to recover water from drilling mud and reserve pit.”

Waste: “NORM,” “NORM-containing materials” (p. 40)

Alternatives – Source Reduction: “Store NORM-contaminated waste in either tanks or lined pits which will accommodate the eventual recovery and proper 

disposal of the NORM-contaminated waste. The contamination of soils with NORM may be averted by not storing NORM containing produced water or other waste 

in earthen pits, thereby decreasing the volume of NORM-contaminated waste.”

Waste: “Pit wastes. Includes: waste in reserve pits and emergency pits” (p. 44)

Alternatives: 

“S: Use rig wash judiciously. Install high-pressure, low-volume spray nozzles with automatic cutoffs.

S: Segregate fresh water, salt water, and oil-based fluids and solids. Use the "reserve pit management system."

S: Remove oil as soon as possible to minimize contamination of pit.

S: Locate and eliminate all sources of water leaks.

S: Grade site and use diversion structures to prevent or minimize stormwater run-on volume.

S: Use a closed-loop drilling fluid system if feasible.
April 1, 2014 Page 86

S: Design pit and pit system to minimize waste. For example, use the "V" shaped pit or the "reserve pit management system."

S: Size and construct pits to accommodate only the necessary volumes anticipated plus an adequate freeboard.

S: Use tanks/vacuum trucks rather than earthen pits for workovers.

R: Stabilized, uncontaminated solids may be suitable for use as daily cover at landfills.

R: Recover and reuse weighting materials and drilling fluids. Waste drilling mud can be reused at other locations for spudding or plugging and abandoning 

operations.

R: Contract a drilling mud recycler to take waste drilling mud.

D: Hazardous: send to an approved, state-permitted RCRA hazardous waste disposal facility.

D: Nonhazardous: send to a state-permitted municipal solid waste landfill.”

(S = source reduction; R = recycling; D =disposal)

Waste: “Rigwash” (p. 46)

Alternatives – Source Reduction: “Collect rigwash in tanks rather than earthen pits.”

Waste: “Soils, crude oil contaminated (in primary field operations)” (p. 48)

Alternatives – Source Reduction: 

- “Develop operational procedures that prevent contamination of soils. For example, preventative maintenance on flowlines and containment under tank 

battery load-line connections.”

- “Use impervious secondary containment. Use pit liner material around and under production facilities.”

Waste: “Soils, lube oil contaminated” (p. 48)

Alternatives – Source Reduction: “Use impervious secondary containment. Use pit liner material around and under lubricating oil systems.”

Waste: “Tank bottoms (basic sediment and water)” (p. 50)

Alternatives:

“S: Recycle back through treatment system, with no additional requirements.

S: Keep turbulent flow in tank to prevent sedimentation whenever possible. The use of mechanical stirring devices in oil storage tanks will eliminate build-up of 

tank bottom sediments and reduce chemical storage.

S: Add appropriate chemical agents to reduce tank bottom accumulation.

S: Treat light oil tank bottoms with high temperature in heavy oil dehydration facilities.

S: Recover product by recycling light oil tank bottoms through heavy oil dehydration facilities. Results: added revenue and substantial cost savings through 

reduction of waste disposal.

S: Use cone bottom stock tanks and run bottoms through heater-treater more frequently than normal.

S: Reduce the number of tanks by consolidating produced fluid storage facilities.

S: Keep a gas blanket on tanks to reduce oxygen and formation of iron oxides. A gas blanket can also reduce risk of explosion and subsequent leakage due to 

lightning strikes...”
April 1, 2014 Page 87

12. Railroad Commission of Texas - Surface Waste Management Manual, December 15, 2010

Website: http://www.rrc.state.tx.us/forms/publications/SurfaceWasteManagementManual/

General Description:

This web-based document provides technical guidelines for management of nonhazardous oil and gas wastes in Texas. 

Specific Sections that Concern Pits:

http://www.rrc.state.tx.us/forms/publications/SurfaceWasteManagementManual/chapter4.php

“Chapter IV- Pits

Disposal or storage of oil and gas wastes in a pit should be allowed only if the activity does not result in the waste of oil, gas and geothermal resources or the 

pollution of surface and subsurface water. The pollution potential for any pit depends on the geology, hydrology and soils in the area, the type and volume of 

waste, and current waste handling and disposal practices. It is recognized that pits associated with oil field activities necessarily must be located near the well sites 

whether the locations are favorable or unfavorable in regard to potential pollution. Pit locations that present the least potential for contamination are in areas of low 

relief to minimize erosion and dike failure. Sites on impervious formations (such as thick, massive clay beds) are preferred over permeable formations (such as 

limestone and sand aquifer recharge zones, terrace deposits and flood plain alluvium). In areas where clay beds do not occur at the land surface, importing off-site 

soils with a high clay and silt content could be considered. In most circumstances, artificial liners are the best alternative.

GEOLOGY AND GROUND WATER

The geology and hydrology across the state is extremely variable. Even across much smaller areas such as a county, large differences occur. Figure 1(pdf) shows 

the major and minor aquifers in Texas. The minor aquifers, while yielding water in smaller quantities or in smaller areas than the major aquifers, are in some areas 

the only source of water supply. While it is impossible to delineate in this manual all the geologic, hydrologic or soil conditions that exist across the State, these 

factors will be evaluated on a case by case basis as an application to maintain and use a particular pit is received by the Railroad Commission in Austin. The 

applicant will be required to determine the distance to the nearest water well within one mile of the pit, the depth of that well, and the depth to the shallowest fresh 

water. Depending on the type of pit construction, a description of the soil material may also be required.

As previously stated, a detailed description of all geologic and hydrologic conditions across the State is not intended. Figures 2 through 4 (pdf) and Figure 5 (pdf) 

show surface pits located in geologic and hydrologic environments with the least potential for ground water contamination.

In Figure 2 (pdf), the pit shown extends below the water table and will cause local contamination. The extremely slow movement of the ground water would prevent 

any significant contamination. Typical ground water flow rates through the clayey sediments under low hydraulic gradients are 0.1 to 0.5 foot per year. The Texas 

Coastal Plain is composed of clays, silts and sands, and the water table is generally within 10 feet of the surface in areas other than near cities, industrialized 
April 1, 2014 Page 88

areas or heavily irrigated areas. The sands and silts are found in old stream and river channels. On-site investigation is necessary to avoid sand and silt zones in 

the clays. The primary concern is contamination of surface water from rainfall traversing the pit and washing the pit contents into surface water drainageways.

The bottom of the pit shown in Figure 3 (pdf) will also intersect the water table during wet seasons. Water movement, however, is very slow, and the dissolved 

mineral concentrations may be altered by ion exchange. The depth of the water table in the clay belts is difficult to measure. Formations appear to be saturated 

because of capillary action above the actual water table. In dry seasons, the water table will be below the bottom of the pit and the relatively impervious clays will 

retard any significant seepage of pit waste to the water table. Properly located pits away from surface drainage on broad upland flats and on divides are preferred.

Figure 4 (pdf) shows a locality where alternating beds of clays, mudstones, marls and shales comprise most of the sediments. These are generally good sites for 

placement of pits. Some of the central and north-central Texas area, however, is covered by alluvial sands and gravels or stream alluvium and terraces. Exposures 

of bedrock generally occur on the sides of broad valleys, between terraces and in upland areas. Locations with sandstones in the sediments, the sandy surficial 

deposits, stream alluvium and terrace deposits should be avoided, if possible, when selecting a pit site. Placement of unlined pits in these materials could result in 

contamination of surface and ground water. Much of north-central Texas uses surface water sources, although some ground water is produced from sandstones, 

and stream deposits. The water table is generally less the 100 feet below the surface. The excavation of thin surficial deposits, which in many areas is less than 

three feet thick, is easily performed and may be necessary to expose suitable material for pit placement.

The major and minor aquifers shown in Figure 1 (pdf) outcrop in most of the State. A more critical review of applications for pits placed in these areas will be 

required. Each major and minor aquifer should have significant amounts of clay, shales, mudstones or other impervious materials as part of its makeup. For 

example, the Carrizo-Wilcox is a major aquifer in southeast Texas, but contains predominately clay and shale formations alternating with sand, clayey sands, and 

sandy clays. The outcrops of the impervious strata are the desirable locations for pit placement. Pits located on sands, silt and gravel outcrops will require an 

artificial liner (i.e., PVC, HDPE, CSPE).

SOILS

The characteristics of the soil at the pit site are a factor in pit construction. Soil characteristics are classified by several methods which fall into two general 

categories, agriculture and engineering. The behavior of a soil as an engineering construction material is the concern in pit construction. The primary engineering 

properties of soils are their texture and their ability to be molded and compacted, called plasticity. For most pits, soils from the excavation will be used to build the 

dikes. Therefore, the native soil must be compactible to prevent seepage and erosion. The soils exposed to the bottom and sides of the pit must also be reworked 

either to form a suitable base for a liner or to retain the fluids in the pit if it is unlined. Often a pit may be deeper than the surface soil layer, which generally is no 

greater than three or four feet thick, and penetrate the subsoil or the unweathered sediments. The subsoil material may be much coarser and more permeable 

than the soil and be unsuitable for pit construction.

Generally, information on the occurrence of soils from an agricultural standpoint are available from the Natural Resources Conservation Service (NRCS) and the 

NRCS county-based office. While data from these sources contain much useful information on the thickness, composition, and permeability of undisturbed soils, 

site-specific data is often necessary to make good engineering judgments.

Field identification of soil samples is the best, and sometimes the only way to gain sufficient information. Again, it is important to know the type of material that will 

compose the pit bottom and dikes. Any on-site sample should be representative of these materials. Explanations of field techniques for determining the texture and 

plasticity of soils are available. When necessary, the services of a soils engineering firm may be utilized.
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PIT DESIGN AND CONSTRUCTION

The pit design and construction techniques described below more frequently apply to pits proposed for long-term, continuous use that must be authorized by 

permit. Pits that are authorized by rule such as basic sediment pits and completion/workover pits generally are less sophisticated in design. Nevertheless, good 

judgment is necessary to avoid seasonal problems of flooding or high water table. If such problems are prevalent, then fabricated tanks should be utilized

All earthen dikes surrounding pits should be constructed of soil material which is capable of achieving a permeability of 1 x 10-7 cm/sec or less when compacted. 

During construction, successive lifts should not exceed nine inches in thickness, and the surface between lifts should be scarified to achieve a good seal. The dike 

height and width should be consistent with the volume of wastewater to be retained. Where wastewater is retained in above ground pits, which will be discussed 

later, it is recommended that the top width of the dike be at least four feet and the side slopes not be steeper than 3 to 1 (three feet horizontal to one foot vertical). 

Dikes for all pits are "keyed" into the underlying soil to achieve a good seal between the ground and the bottom of the dike to prevent lateral seepage of 

wastewater through the base of the dike. (see Figures 5, 6, 7, and 8)(pdf)

Two of the most common construction methods for pits are "above ground" and "below ground". The above ground pit should be used in areas where the water 

table is high. The above ground method consists of constructing dikes around the area without excavating below the surface (see Figure 5) (pdf). The dike material 

can be obtained entirely from a borrow pit as in the case of Pit A, or the area intended for the pit can be excavated slightly and leveled to obtain material for the 

dikes (Pit B). Pits A and B are not lined because the underlying soil is relatively impermeable (K< or = 1.0 x 10-7 cm/sec) and of sufficient thickness (>2 feet) to 

inhibit seepage into the ground water. Because the wastewater level in this type of pit will be above ground level a breach in the dike might result in contamination 

of surface waters. Therefore, it is very important that the dikes around the above ground pit be properly engineered and constructed. Pits C and D in Figure 6 (pdf) 

are constructed in the same manner as those shown in Figure 5 (pdf) except that they are lined. The underlying sediments are relatively permeable (K> 1.0 x 10-7 

cm/sec) and clays in the soil are not of sufficient thickness to prevent seepage of wastewater into the ground water.

The "below ground" method of constructing a pit consists of excavating an area and building dikes around the excavation (see Figure 7(pdf). The below ground pit 

should be used in areas where the water table is well below the surface. The pits in Figure 7 (pdf) are not lined because the underlying material is relatively 

impermeable and of sufficient thickness to inhibit seepage to the water table. Pit E is the preferred method of construction. The wastewater level in this pit will 

under normal conditions be at ground level or below. Therefore, the probability is low of wastewater flowing into area drainage if the dike is breached. The 

wastewater level in Pit F normally will be above ground level, requiring greater care in the engineering and construction of the dikes. The pits shown in Figure 8

(pdf) are lined because of the permeable underlying soils.

LINERS

A liner is a continuous layer of materials that serves to restrict the release or migration of oilfield fluids, oil and gas wastes, or waste constituents. A liner may be 

constructed of synthetic or natural materials. 

A liner must:

· Have a permeability low enough to contain the material.

· Be chemically compatible with the material with which it is expected to come into contact.

· Be mechanically compatible with the operation.
April 1, 2014 Page 90

· Be capable of maintaining its integrity over time.

GEOMEMBRANE LINERS

Flexible membrane liners, or geomembranes are impervious thin sheets of synthetic polymer material. The most widely used geomembranes are high density 

polyethylene (HDPE), polyvinyl chloride (PVC), very low density polyethylene (VLDPE), and chlorosulfonated polyethylene (CSPE); of these, HDPE is used the 

most

Commercially available geomembrane liners should all have sufficiently low permeability (typical permeability values are 0.5 x 10-10 cm/sec or less); therefore, the 

concern is that the liners be chemically compatible with the material to be stored and possess physical and mechanical properties which enable them to survive 

installation and operation. Other important considerations are resistance to ultraviolet degradation and thermal degradation. The American Society for Testing and 

Materials (ASTM) has adopted a number of standards for geomembrane liners. Other ASTM standards for plastics and rubber may be applicable, as well as EPA 

developed test methods. In general, the operator will need to rely upon testing which has been performed by the manufacturer. The manufacturer should be able 

to provide results of verification testing which has been performed by an independent laboratory. The verification testing should have been performed on the actual 

batch of liner material to be used

Chemical Compatibility

Chemical compatibility is of prime concern when selecting a liner. Manufacturers and vendors have evaluated the resistance of their liners to many chemicals. 

These are available in the form of chemical resistance charts. If the fluid to be contained is not on the chart, or consists of a mixture of chemicals, compatibility 

testing of the specific fluid/liner combination may be warranted. 

Mechanical Compatibility

The geomembrane must first survive transportation and installation, avoiding tear, puncture, and impact. Deformations caused by settlement of subgrade soils and 

backfilled zones beneath the liner are the prime mechanical consideration in the selection of a liner. Pit liners may also be subjected to weather, inflow and outflow 

of fluids, abrasion, hydrostatic pressure, thermal stress, cleaning and maintenance stress, and exposure to animals. Geomembrane manufacturers should provide 

results of testing for mechanical properties such as tensile properties, tear resistance, impact resistance, and puncture resistance. Mechanical properties are 

proportional to liner thickness, therefore, thicker liners are correspondingly more resistant to mechanical damage.

Maintain Integrity over Time

In addition to chemical and mechanical degradation as noted above, liners are also subject to thermal and ultraviolet degradation. Ultraviolet degradation occurs 

due to natural sunlight; thermal degradation occurs at both high and low temperatures. ASTM test methods are available to evaluate these properties and 

manufacturers should be able to provide test results. Exposed liners must contain carbon black or other pigments to minimize ultraviolet degradation. Liner 

degradation can be limited by initial selection of the proper liner and the use of appropriate operating procedures during the life of the pit. Earth covers may be 

used to protect liners from sunlight and mechanical damage, however, this does not allow for visual inspection of the liner.>
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Installation

Compaction of the subgrade soil is required to provide a firm and unyielding base for the lining materials. Generally, a fill subgrade is built-up in a series of 

compacted layers, while an excavated subgrade is compacted only at its surface. The regularity and texture of the surface of the uppermost layer of compacted 

material is critical prior to liner installation. After compaction has been completed, the surface should be finished. This is best accomplished by looking for and 

removing rocks, debris or irregularities with sharp edges. Drags, vibrating rollers and smooth steel rollers are common tools for fine finishing the bottom and 

sidewalls of the pits. The fine finishing process is dependent on care and control of water. Liner placement should be halted when rainfall is imminent, and the 

placement of liner materials on the fine finished slopes should take place as soon after the completion of "finishing" as possible to ensure that no surfaces are lost 

to the erosive effects of surface runoff (see Figure 9(pdf). 

The most likely place for a leak to occur is at the seams. The number of seams should be minimized. Seams should be oriented up and down, not across a slope. 

Factory seams should be used where possible. All field seaming should be performed by qualified personnel.

COMPACTED SOIL LINERS

Compacted soil liners are constructed of soils containing clay, which are spread and compacted in layers or lifts. These liners are not generally appropriate for the 

primary liner in pits containing produced water, brine, or other mineralized waters, but may be appropriate for certain applications. Soils classified as CL, CH, or 

SC in the Unified Soil Classification System are typically used to construct liners. To be adequate, a compacted soil liner should have a thickness of two feet or 

more and a hydraulic conductivity of 1 x 10-7 cm/sec or less. Compaction to 95% standard Proctor at a soil moisture content of 2 to 3% wet of optimum is 

appropriate. A primary advantage of compacted soil liners is their ability to self-seal when the liner is penetrated. 

OTHER

Other liners may be suitable in some circumstances. These lining materials may include concrete and asphalt concrete, as well as blended or admixed liners of 

soil and cement, soil and asphalt, and soil and bentonite. The acceptability of any liner depends on the climate and hydrogeology of the pit location, and the 

intended pit use. 

LEAK DETECTION SYSTEMS

Leak detection systems for synthetic liners will be required for brine and brine mining pits. Detection systems will not normally be required for liners of any type of 

other pit unless the pit is located in a very hydrologically sensitive area. Some common underdrain systems consist of a gravity flow drainfield and collection points 

installed either under the pit liner and above a secondary liner or outside of the pit.

Figure 10 (pdf) illustrates a sloping drainfield of coarse porous material that allows wastewater that has passed through the pit liner to accumulate at the low end of 

the pit above a secondary liner. A riser pipe perforated or slotted in the drain material interval extends from the collection point to the ground surface or along the 

sloping pit wall and berm. By extending a tape or long, small diameter, cylindrical rod into the riser pipe, the presence of wastewater in the pipe can be determined. 

This type of underdrain system can be used for relatively deep pits.

Figure 11 (pdf) also illustrates a sloping drainfield of coarse, porous material that allows wastewater that has passed through the pit liner to accumulate at the end 

of the pit above a secondary liner. A drain pipe connects the collection point to a sump or trench constructed outside of the pit. The presence of wastewater in the 

sump or trench indicates a leaking liner. This type of underdrain system can be used for above ground or slightly excavated pits. Manufacturers of the various 

artificial liners also may have information on leak detection systems.
April 1, 2014 Page 92

Geonets are highly efficient at transmitting fluids in the plane of the net and can be used to replace granular drainage layers in leak detection systems. Geonets 

are geosynthetic drainage materials composed of layers of parallel ribs or strands overlying similar layers at various angles. Virtually all commercially available 

geonets are made of HDPE. Geonets are available from manufacturers and vendors of geomembrane liner systems. Manufacturers should be able to provide test 

results and information on mechanical and hydraulic properties. When installed, geonets must have both surfaces covered with a geomembrane, geotextile, or 

other suitable material to prevent intrusion of soil into its openings. Geonets occupy less vertical space in the excavation and are typically easier to install than 

granular drainage layers. 

Regular inspections should be made of the embankment and the berms. In particular, attention should be given to possible ground movement, cracks and erosion 

of the earth because failure of the earthwork can result in failure of the liner. Damage to the liner can also result if weed growth begins under the liner, or if a soil 

cover is present, on top of the liner. The berm area around the pit should be treated with a weed killer initially and maintained in a weed-free condition.

Operational procedures which may endanger the integrity of a lined pit are:

1. discharge of high-temperature waste liquids onto exposed or unprotected liners;

2. operation of a vehicle over any portion of an exposed liner;

3. discharge of a waste to the pit that is incompatible with the liner; and/or

4. direct discharge of liquid waste under high pressure.”

Clarification for Filing Application to Maintain and Use a Pit (Form H-11)

http://www.rrc.state.tx.us/forms/publications/SurfaceWasteManagementManual/2010-FracPicNotice.pdf

“Due to new technology much larger pits are now needed for the storage and mixing of fresh water and fracture flow-back water. Many of these pits are

constructed to store wastewater above ground level. The design of these

large pits where waste is stored above ground level is considered the practice of engineering and must be prepared under seal of a registered engineer as

required by the Occupations Code Chapter 1001.

Many pits used for the storage of fresh water are converted for the use of mixing fresh water and fracture flow-back water. While the use of a pit to store fresh 

water does not require a permit, an application for a permit to maintain and use a pit (Form H-11) must be submitted for the converted use. A proposal to store 

waste above ground level within dikes must be prepared under seal of an engineer registered in Texas.

It is recommended that if it is known that a fresh water pit will be eventually converted for use as a fracture flow-back pit, an engineer be involved in the design and 

construction of the pit.”
April 1, 2014 Page 93

Specific Sections that Concern Land Application:

http://www.rrc.state.tx.us/forms/publications/SurfaceWasteManagementManual/chapter5.php

Chapter V- Discharges and Land Disposal

LANDFARMING

“Landfarming of the following oil and gas wastes is acceptable without a permit provided the wastes are disposed of on the same lease where they are generated, 

and provided written consent of the surface owner of the tract where the landfarming will occur is obtained: water base drilling fluids with a chloride concentration 

of 3000 mg/l or less; drill cuttings, sands and silts obtained while using water base drilling fluids with a chloride concentration of 3000 mg/l or less; and wash water 

used for cleaning drill pipe and other equipment at the well site. Other landfarming operations require a permit.

Landfarming is a method of treatment and disposal of low toxicity wastes in which the wastes are spread and mixed into the soils to promote reduction of organic 

constituents and dilution and attenuation of metals. A permit application to landspread water base drilling fluid and associated cuttings, a permit application to 

landtreat oil and gas wastes, and a permit application to land apply produced water are each by letter of request. Landfarming utilizes the physical, chemical and 

biological capabilities of the soil-plant system to control waste migration and to provide a safe means of disposal without impairing the potential of the land for 

future use. Landfarms should be located on fine or medium grained soil with a thickness of at least 20 inches and a slope of less than five percent. Stormwater 

runoff must be controlled by either natural drainage features or by diversion structures. Landfarms should not be located in any area prone to flooding.

The application of fluid waste should be designed so that direct runoff of waste does not occur and so that the soil-plant system is not subject to prolonged 

saturation. Overloading can damage vegetation, produce odors, and limit oxygenation of the soil. Landfarming operations are limited by severe weather conditions. 

Wastes should not be applied during rainy weather to reduce the possibility of contaminated runoff and the excessive compaction of the soil by machinery.

Waste liquids and slurries can be applied to the land surface or injected beneath the surface. Sprinkler irrigation, flood irrigation, ridge and furrow irrigation, and 

surface spreading from hauling vehicles are methods of surface application. Subsurface application can be accomplished by injection plowing or by following a 

surface application with a disc or plow. This method is more effective in minimizing runoff contamination, controlling odors, and degradation of oil and grease or 

other organic waste.”
April 1, 2014 Page 94

13. U.S. Fish and Wildlife Service (Arkansas Field Office) - Best Management Practices for Fayetteville Shale Natural Gas 

Activities, April 2007

Website: http://www.fws.gov/arkansas-es/docs/AR_Natural_Gas_Pipeline_BMPs_v2_April_2007.pdf

General Description:

This document was developed by a multi-agency workgroup. It provides guidance for natural gas exploration, drilling, and production 

operations in the Fayetteville Shale area in Arkansas. 

Specific Sections that Concern Pits and/or Tanks:

2.0. Wetlands (p. 10) 

“2.2. Drilling sites subject to inundation due to over bank flooding should use a closed loop system to prevent drilling fluids from entering the system during floods.”

4.0. Construction Activities (pp. 12-13)

“4.4. Well sites should be located to avoid sensitive resources (contact FWS, AGFC, and ANHC to identify sensitive resources). A closed mud system or steel 

tanks should be utilized to drill the well in sensitive habitats, wetlands, state-owned natural areas, wildlife management areas, and national wildlife refuges. In 

sensitive habitats, all fluids and cuttings should be hauled off site for disposal in accordance with AOGC and ADEQ requirements. Non-sensitive areas also should 

follow APCEC and AOGC regulations for disposal. Surface tanks must have berms sufficient to contain 1.5 times the total volume of all tanks. The berm area must 

be lined sufficient to prevent any leakage, and rip-stop padding must be used to prevent tears or punctures in liners. AOGC General Rule B-1 requires that a 

permit be issued before drilling can commence therefore a control point of knowing when and where this activity will occur before it occurs.”

“4.5. The area used for mud tanks, generators, mud storage, and fuel tanks should be sloped slightly, where possible, or a suitable alternative should be used to 

provide surface drainage from the work area to a secondary pit (not the reserve pit – ADEQ regulations). AOGC General Rule B-26 establishes requirements for 

secondary containment. Reference BMP 4.4 for additional guidelines.”

“4.6. Well pads should be capable of supporting the drill rig, tanks, heater-treater, and other production equipment. All equipment should be located on compacted 

fill material. Slope the well pad to the well cellar or other low point to collect spills and contaminated storm water that collects within the lined area (e.g., a separate 

pit should be used for collection of storm water [hydraulic fluids, honey oil, pipe dope, and other mechanical fluids that may spill onto the well pad and are 

prohibited by APCEC regulations from entering the reserve pit and being land applied]).”

“4.14. A berm and fence with locked gate should be constructed around storage tanks to contain spills and protect wildlife, visitors, and guard against vandalism. A 

sign with site name, operator name, and emergency contact information should be posted at the gate. AOGC General Rules prescribe containment and

identification requirements.”
April 1, 2014 Page 95

“4.15. Berms should be designed and constructed with sufficient perimeter and height to hold 1.5 times the volume of the largest tank. Containment systems with

corrugated galvanized steel are available as an alternative to earthen dikes. Another option is to place a synthetic liner beneath the tanks, fold the liner into the 

berm, which then can be reinforced with a cement mixture. AOGC General Rule B-26 establishes requirements for secondary containment.”

“4.16. Interim reclamation of the drill site should be completed within six months of well completion. Interim reclamation plans including production equipment or 

facility site diagrams should be provided to the appropriate agency prior to drilling. Additional consultation may be required to determine final drill site dimensions. 

Reserve pit closure should occur within 30 days in sensitive habitats and adhere to APCEC regulations in other areas.”

“4.19. Reserve Pits

a. Closed loop systems (refer to definition below) are strongly recommended on publicly-owned properties and recommended on private lands located near

sensitive areas, including flood plains. Closed loop systems require smaller pad sizes and are the safest protocol for avoiding environmental contamination.

Closed Loop System: a typical closed-loop system includes a series of linear motion shakers, mud cleaners and Centrifuges followed by a dewatering system. The

combination of equipment typically results in a “dry” location where a reserve pit is not required.

b. Reserve pits should be located entirely in cut material. Avoid areas with shallow groundwater and waterbodies.

c. The reserve pit should be designed to contain all anticipated drilling muds, cuttings, and precipitation while maintaining a minimum two feet of freeboard.

d. ADEQ pit liner requirements include an impermeable liner (clay, synthetic, or combination) to prevent ground water and soil contamination and conserve water.

e. Oil based mud should not be used or stored in reserve pits during waterfowl migration periods (November to March). In some situations, netting may be required 

in order to prevent mortality of migratory birds (refer to BMP 1.8). Reserve pits with oil-based mud must use a synthetic liner per ADEQ regulations however, 

closed systems are encouraged. If site conditions warrant (i.e., floodplain, near waterbody, wellhead protection area, or other significant site issues), ADEQ or 

Arkansas Department of Health (ADHS) could require additional construction requirements.

f. Reserve pits should be fenced to prevent access by persons, wildlife, or livestock. The fence should remain in place until pit reclamation begins.

g. The operator must properly dispose of drilling fluids and muds from the reserve pit to a permitted facility and reclaim the pit area as soon as practicable following 

completion of drilling activities.

h. When closing reserve pits, follow the Arkansas Department of Environmental Quality Reserve Pit requirements (Refer to Appendix C for more information).”

6.0. Disposal of Produced Water, Drilling Fluids, Fracturing Fluids, Biocides, or Other Specialty Chemicals (p. 15)

6.3. Secondary containment of produced water tanks is strongly encouraged.

8.0. Well Servicing and Workover Operations (p. 15)

“8.1. Strategies for clean well servicing and work over operations include:...”

“b. Use a synthetic liner and board matting under rig components and construct berms/trenches to direct liquids to cellar when location conditions require it.”

“c. Use steel tanks to hold work over fluids and all liquids and solids returned from the well until they can be removed from the site...”
April 1, 2014 Page 96

14. Natural Resources Law Center - Intermountain Oil and Gas BMP Project

Website: http://www.oilandgasbmps.org/index.php

General Description:

This is a free-access website of voluntary management practices for oil and gas development in the Rocky Mountain Region. The 

database includes mandatory and voluntary management practices currently used or recommended for responsible resource 

management in the states of Colorado, Montana, New Mexico, Utah, and Wyoming. It is not intended to represent a consensus on the 

management practices for specific applications. The database describes each management practice, documents the source, provides a 

link to the source, and provides supplemental information.

Specific Sections that Concern Pits, Tanks, and/or Land Application:

- Search directory for information on voluntary management practices.
April 1, 2014 Page 97

6. Findings 

EPA agrees with the recommendation of the Shale Gas Subcommittee of the Secretary of Energy’s Advisory Board (SEAB) that the 

federal government should encourage the development of additional and improved “best practices.” Based on the review of existing 

voluntary management practices documents, ORCR determined that there is much existing guidance developed and being used by 

industry, federal, state, and non-governmental organizations. The scope ranges from local to state, regional, national, and 

international. The guidance documents compiled in this review are readily available to the public. In addition, there are ongoing 

efforts by the various stakeholder groups to continuously develop additional guidanceses and improve existing ones. 

The voluntary management practices examined in ORCR’s review are intentionally general rather than prescriptive due to the sitespecific nature of E&P. Many of the documents recommend that users select the appropriate management practices for their specific 

needs. The general approach allows users the flexibility to select the management practices and adapt them to meet the site-specific 

requirements of the individual projects and the local conditions. 

Many, but not all, of the documents examined in this review include recommended general technical criteria for E&P pits and tanks 

covering some or all of the following areas: general, permitting, construction, operational (including maintenance, inspection, 

monitoring, data collection, testing, remediation), and closure. However, as previously noted, EPA did not evaluate the adequacy or 

protectiveness of any of the voluntary management practices summarized in this document.

 
April 1, 2014 Page 98

Disclaimer:

This document does not represent and should not be construed to represent any Agency determination, policy, or 

regulation. This document may not be relied on to create any rights, substantive or procedural, enforceable by any 

party in litigation with the United States. Inclusion of documents in this report does not constitute a US EPA 

endorsement of their contents, only an acknowledgment that these documents exist and describe voluntary 

management practices for oil and gas exploration and production (E&P) wastes as they address pits, tanks, and 

land application. . The use of the phrase “Best Management Practices” throughout this document is not intended 

to suggest that EPA has concluded that these particular practices are in fact “best management practices” or that 

adoption of these practices will protect human health and the environment. Mention of trade names or commercial 

products does not constitute endorsement or recommendation for use.