water issues in oil and gas production -...

National Energy Technology Laboratory

Driving Innovation ♦ Delivering Results

The Status of the Technology, DOE’s Recent Contributions,

and Current Research Needs

Charles E. Taylor, Ph.D.

International Activities Manager

Water Issues in Oil and Gas Production

2 National Energy Technology Laboratory

Outline

• Water in Oil and Natural Gas Production

– Key Challenges

– Industry Solutions

• DOE Oil and Gas Research Program

– Categories

– Performers

– Successes

• Current Research Needs


Oil and Natural Gas “Water” Challenges

• Find Non-Freshwater Alternatives

• Reduce Freshwater Requirements

• Lower Treatment Costs

• Ensure Safe/Economic Disposal

• Reduce Produced Water Volumes

• Lower Treatment and Disposal Costs

• Support Beneficial Reuse

• Follow Drilling and Well Completion Best Practices to Protect Fresh Water Sources

• Improve Methods for Locating and Plugging Abandoned Wells

• Reduce Risk of Induced Seismicity

Produced Water

Fracturing Water Fresh Water Protection

Water Disposal


Shale Well Flowback Water Versus Produced Water

The portion of injected frac fluids that return to surface before production. Typically 10-20% returns quickly in 7-14 days with a rapid decline in quality and quantity

Wat

er

Pro

du

ctio

n

< 30 Days ~ 30 Years

Flowback Water

Produced Water

Adapted from www.dowwaterandprocess.com


Industry’s Solutions to Fracturing Water Issues

• Recycle as much fracture flowback as possible using chemical additives, low cost filtration, and dilution procedures

• Reduce costs of freshwater supply by centralizing storage and using flexible distribution systems

• Apply water treatment options to solve specific problems in the most cost effective manner possible

• Continue to dispose of waste water that cannot be re-used via Class II UIC wells

Fracturing flowback water before and after filtration and dilution


Industry’s Approach (In Order of Increasing Cost)

1. Blend untreated flowback and produced water with fresh water and reuse

2. Filter flowback and produced water and blend with fresh water

3. Add salt-tolerant friction reducers, anti-scalants and biocides to enable higher proportions of flowback and produced water to be blended

4. Transfer flowback and produced water to permitted central treatment facilities for more intensive treating before reuse

5. Transfer flowback and produced water that cannot be recycled to permitted brine disposal wells


Reuse of Fracture Flowback Growing Steadily

Southwestern Energy water sources for Fayetteville Shale Play development 2007-2013

Vo

lum

e, M

Mb

bls

[CELLRANGE]

[CELLRANGE] [CELLRANGE]

[CELLRANGE] [CELLRANGE]

[CELLRANGE]

0

10

20

30

40

50

60

70

80

2007 2008 2009 2010 2011 2012 2013

SWN Ponds Private Sources Water Reuse Municipal Sources

No. Wells Stimulated

290 556 357 469 528 477 437

Note: Stimulated lateral length has steadily grown over time


Fracturing Additive Chemistry Has Advanced

Salt-tolerant friction reducer vs. traditional friction reducer enables a 258,000 ppm TDS produced brine to nearly match the performance of a fracturing fluid mixed with fresh water


Recycle Treatment Options

Technology Bag Filtration Physical/Chem-ical Separation

Electro-Coagulation Chlorine Dioxide Treatment

Evaporation/ Distillation (MVR)

Crystallization

Total Suspended Solids (TSS)

+ + + + + With Pretreatment

+ With Pretreatment

Metals + + + + With Pretreatment

+ With Pretreatment

Bacteria + + + + With Pretreatment

+ With Pretreatment

Barium + + With Pretreatment

+ With Pretreatment

Hardness (Ca) + With Pretreatment

+ With Pretreatment

Total Dissolved Solids (TDS) + +

Limitations

Disposal of spent filter bags can be

costly

Can have large chemical usage and solids processing/

land-filling

Requires very consistent raw water

quality. Can have high electrical requirements

Danger generating and using chlorine dioxide. Can be costly. Have to pay close attention to system performance

High energy usage. High

cost. Rigorous pretreatment.

High energy usage. High costs. Requires

very consistent/ stable raw water

influent water quality.


Simple Filtering is the First Step

Bag filters employed for filtering flowback water prior to reuse in hydraulic fracturing


More Aggressive Technologies Follow if Necessary

Electro-coagulation systems for treating fracturing flowback water in Colorado


Treatment Facilities Designed for Specific Needs

Southwestern Energy’s Judsonia, AK Reuse and Recycling Center services Fayetteville Shale Play development. Concentrated brine can be reused, distilled water can be reused or discharged.

1. Unloading Bay 2. Sedimentation Basins 3. Impoundment (Biological) 4. Loading Tank/Station (for Reuse/Brine Disposal) 5. Treatment Pad (IGF/MVR) 6. Verification (Holding) Tanks 7. Discharge Point 8. Brine Tank for Reuse/Disposal

3 2 7

4

1

8 5 6

Biological Treatment and

Storage

TDS: 43,000 ppm Feed: 2,500 bpd

Treated Water

2,475 bpd TSS < 10 ppm

Induced Gas Flotation (IGF)

Mechanical Vapor Recompression

Distilled Water

1,962 bpd TSS < 100 ppm

Concentrated Brine

538 bpd TSS: 200,000 ppm

IGF Skim

50 Micron Filter

To Disposal Well or Reuse

To NPDES Discharge of Alternate Use

2X Units 1,250 bpd Each

1X Units 2,500 bpd

1% of Feed 25 bpd


Industry Solutions to Produced Water Issues

• Use produced water for fracturing/EOR where possible/economic

• Apply techniques for reducing volumes of water produced if they prove cost-effective

• Direct produced water to beneficial re-use if practical and cost-effective (these situations are limited to places where the produced water is relatively fresh and there is a local need)

• Continue to dispose of produced water via Class II UIC wells

Chevron supplies produced water for crop irrigation in Kern Co. California


Industry Solutions to Water Protection Issues

• Address surface hole drilling and zonal isolation issues by following existing regulations and industry best-practices and standards

• Test shallow water aquifers using third-party services before drilling to establish pre-drilling baseline Flowback water collection and storage

tanks at Marcellus Shale play well pad

• Broaden use of closed system hydraulic fracturing equipment and other methods for reducing risks of surface spills

• Continue to dispose of waste water via Class II UIC wells


Industry Solutions to Water Disposal Issues

Class II UIC well distribution across US

• Follow all regulations regarding disposal of water via Class II UIC wells

• Implement cost-effective practices that serve to reduce the volume of water that must be disposed of, either fracturing flowback water or produced water


Industry Approach Has Changed Over the Past 5+ Years

• Advances in fracturing additive chemistry have enabled the industry to replace freshwater sources with fracturing flowback, brackish groundwater, produced water, and other non-potable sources.

• Treatment technology innovations continue to make reuse of flowback and produced water more technically and economically feasible.

• Improvements in water conveyance have reduced truck traffic and associated environmental impacts.

• New water storage designs are flexible, reliable, leak resistant and exhibit low evaporation loss.

• Water monitoring innovations for tracking water use enhance transparency.

• Evolved company organizational structures now often include water management teams that focus on managing the full water cycle from sourcing to use, recycling, and disposal.


DOE Fossil Energy Research Program

• 59 projects initiated since 2008 with a total value of more than $104 million

• 34 projects remain active, with expected completion dates through September 2017

• Major focus has been water treatment technologies, accounting for about 40% of projects and 1/3 of funding

• Program covers a broad range of water-related issues (e.g., improved cementing technology to protect aquifers)

• NETL-ORD research is focused on risk assessment and basic science surrounding a host of water issues


DOE Fossil Energy Water Project Categories

Category Number of

Projects Active

Projects

Total Value* (MM$)

Water treatment technology development 25 14 33.4

Basic science and risk assessment (NETL ORD in-house research)

8 5 na

Water management tool development 6 2 8.4

Improved annular isolation 5 4 19.2

Environmental impact reduction 3 2 14.3

Alternatives to water as fracturing fluid 3 3 7.6

Enhanced water disposal options 2 0 2.1

Other (e.g., beneficial use, water chemistry, induced seismicity, volume reduction)

7 4 19.4

Totals 59 34 104.4

* Average partner cost share is about 30%, DOE funding about 70%


DOE Fossil Energy Water Project Performers


Two Marcellus Wastewater Treatment Facilities Open with DOE-Tested Technology

• Located in Clarion County and McKean County, Pennsylvania

• Energy-efficient AltelaRain® thermal distillation process captures heat from condensation, uses it during evaporation

• Capacity = 12,000 barrels of wastewater per day per plant

• Discharge water exceeds Pennsylvania Department of Environmental Protection requirements


FracFocus Website Developed and Maintained via DOE Funding to GWPC

• Contains publically available data on fracturing treatments for more than 93,000 wells fractured after Jan 1, 2011

• 1109 companies have contributed data as of Feb 26, 2015

• New websites features will facilitate data downloads and analysis by any interested stakeholder

• Many producing states are incorporating FracFocus into reporting requirements

https://fracfocus.org/


NETL Field Experiment Provides Evidence That Fracturing Does Not Reach Water Aquifers

• Greene Co. PA well pad field site, Marcellus Shale fractured at 2,434+ meter depth

• Monitored sands at 610 to 1,372 meter depths; aquifers <305 meters

• Combined microseismic, pressure/production, water and natural gas isotopes, and perflourocarbon tracer analyses

• No indication of communication via fractures or faults

http://www.netl.doe.gov/File%20Library/Research/onsite%20research/publications/NETL-TRS-3-2014_Greene-County-Site_20140915_1_1.pdf


NETL Methods for Locating Abandoned Wellbores

• Airborne magnetic surveys followed by surface surveys

53500 nT

53000 nT

Total Magnetic

Intensity Marcellus Wellpad

250 0 250 Meters

• Research showed PA state well location database deficient or in error (well positions >100m off, survey found 17 wells of which only six were in state database

• Locating abandoned wells key to eliminating conduits for gas contamination of potable water aquifers during Marcellus shale gas development

Horizontal Wells (Proposed)


Suggested Research Projects

• Evaluate the need for new technologies/approaches to address future high TDS water management problems in areas lacking water disposal options (e.g., Pennsylvania). Begin by projecting 2015-2040 cumulative produced water rates, volumes and compositions for major shale plays, to identify areas where expected water volumes/compositions could present problems.

• Develop specific water treatment technologies designed to enhance the economics of using mine drainage as a water source in the Marcellus and Utica

• Develop specific water treatment technologies that can help to lower the costs of treating non-potable water sources for fracturing in shale plays in water stressed areas (e.g., Texas, Rocky Mountain States)

• Continue to investigate the relationship between wastewater injection and seismic activity; refine best-practices and support development of standards


It’s All About a Clean, Affordable Energy Future

For More Information, Contact Charles Taylor

[email protected]

+1-412-386-6058

National Energy Technology Laboratory 25


NPDES OVERVIEW

http://water.epa.gov/polwaste/npdes/

As authorized by the Clean Water Act, the National Pollutant Discharge Elimination System (NPDES) permit program controls water pollution by regulating point sources that discharge pollutants into waters of the United States. Point sources are discrete conveyances such as pipes or man-made ditches. Individual homes that are connected to a municipal system, use a septic system, or do not have a surface discharge do not need an NPDES permit; however, industrial, municipal, and other facilities must obtain permits if their discharges go directly to surface waters. In most cases, the NPDES permit program is administered by authorized states. Since its introduction in 1972, the NPDES permit program is responsible for significant improvements to our Nation's water quality.


Class II wells inject fluids associated with oil and natural gas production. Most of the injected fluid is salt water (brine), which is brought to the surface in the process of producing (extracting) oil and gas. In addition, brine and other fluids are injected to enhance (improve) oil and gas production. The approximately 151,000 Class II wells in operation in the United States inject over 2 billion gallons of brine every day. Most oil and gas injection wells are in Texas, California, Oklahoma, and Kansas.

What is a Class II well?

http://water.epa.gov/type/groundwater/uic/class2/


1. Enhanced Recovery Wells inject brine, water, steam, polymers, or carbon dioxide into oil-bearing formations to recover residual oil and—in some limited applications—natural gas. This is also known as secondary or tertiary recovery. The injected fluid thins (decreases the viscosity) or displaces small amounts of extractable oil and gas, which is then available for recovery. In a typical configuration, a single injection well is surrounded by multiple production wells. Production wells bring oil and gas to the surface; the UIC Program does not regulate wells that are soley used for production. However, EPA does have authority to regulate hydraulic fracturing when diesel fuels are used in fluids or propping agents. During hydraulic fracturing, another enhanced recovery process, a viscous fluid is injected under high pressure until the desired fracturing is achieved, followed by a proppant such as sand. The pressure is then released and the proppant holding the fractures open allows fluid to return to the well. Enhanced recovery wells are the most numerous type of Class II wells, representing as much as 80 percent of the approximately 151,000 Class II wells.

What are the types of Class II wells?



2. Disposal Wells inject brines and other fluids associated with the production of oil and natural gas or natural gas storage operations. When oil and gas are produced, brine is also brought to the surface. The brine is segregated from the oil and is then injected into the same underground formation or a similar formation. Class II disposal wells can only be used to dispose of fluids associated with oil and gas production. Disposal wells represent about 20 percent of Class II wells.

3. Hydrocarbon Storage Wells inject liquid hydrocarbons in underground formations (such as salt caverns) where they are stored, generally, as part of the U.S. Strategic Petroleum Reserve. There are over 100 liquid hydrocarbon storage wells in operation.

What are the types of Class II wells?



When oil and gas are extracted, large amounts of brine are typically brought to the surface. Often saltier than seawater, this brine can also contain toxic metals and radioactive substances. It can be very damaging to the environment and public health if it is discharged to surface water or the land surface. By injecting the brine deep underground, Class II wells prevent surface contamination of soil and water. When states began to implement rules preventing disposal of brine to surface water bodies and soils, injection became the preferred way to dispose of this waste fluid. All oil and gas producing states require the injection of brine into the originating formation or into formations that are similar to those from which it was extracted.

How do Class II wells protect drinking water resources?



A state has the option of requesting primacy for Class II wells under either section 1422 or 1425 of the Safe Drinking Water Act: Section 1422 requires states to meet EPA’s minimum requirements for UIC programs. Programs authorized under section 1422 must include construction, operating, monitoring and testing, reporting, and closure requirements for well owners or operators. Enhanced oil and gas recovery wells may either be issued permits or be authorized by rule. Disposal wells are issued permits. The owners or operators of the wells must meet all applicable requirements, including strict construction and conversion standards and regular testing and inspection. Section 1425 allows states to demonstrate that their existing standards are effective in preventing endangerment of USDWs. These programs must include permitting, inspection, monitoring, and record-keeping and reporting that demonstrates the effectiveness of their requirements.

What are the requirements for Class II wells?


http://altelainc.com/wp-content/uploads/2015/04/AltelaRain-750-Collateral-NP-2014.pdf


Figure 1: Map of

east-central United

States showing

occurrence of

Marcellus Shale

(red shading) and

Marcellus Shale

wells (black dots).

The occurrence of

the Utica formation

is shown with blue

shading. The study

area is in Greene

County, PA (outlined in yellow).




Figure 2: Vertical section from a

Marcellus Shale gas well (MW-2)

showing the depth relationship

between the hydraulically

fractured formation (Marcellus

Shale), the monitoring zone

(Upper Devonian/Lower

Mississippian sands), and

protected freshwater aquifers (USDW).



water issues in oil and gas production -...

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