Assessment of Deep-Well Injection of Liquid Wastes from Hydraulic Fracturing

Ronald T. Green, Ph.D., P.G. and F. Paul Bertetti, P.G. Geosciences and Engineering Division

Southwest Research Institute®

Eagle Ford Center for Research, Education, and Outreach

November 18, 2014

Issues for Hydraulic Fracturing Operations

EPA, 2011

Narrowly Framed Discussion of Hydraulic Fracturing

EPA, 2011

Full Life Cycle of Fracking is Important

EPA, 2011

How Much Water Does Fracking Use? (Per Well)

• Conventional oil/gas well requires 100,000 gallons

• To frack one stage of a horizontal well requires 300,000 gallons

• Horizontal well could have 15-25 stages

• Total water required to frack a horizontal well: >5,000,000 gals

• Rate: 4-8 stages/day requires 1,200,000-2,400,000 gallons per day

How Much Water Does Fracking Use? (Total Water Consumption)

• About 1/3% of all freshwater used in U.S.

• About 1% of all freshwater used in Texas

• About 6% of all freshwater used in southern Texas

• About 1/3 to 1/2 of all recharge in SW segment of Eagle Ford play

• How much water is a local issue, regional averages don’t matter when your well goes dry

Handling and Disposal of Waste Fluids Poses Greatest Risks

EPA, 2011

Fracking Flowback and Produced Water What Happens to It?

• Recycle and reuse of fracking flowback and produced water is

an area of active development, many promising technologies.

Limitation is capacity.

• Disposal of waste fluids poses greater risks: pits, tanks, pipes,

trucking, injection, treatment, etc. These risks have not been

adequately assessed.

Deep-Well Disposal of Waste Fluids

• Energy Policy Act of 2005 specifically exempts fracking fluids from Safe Water Drinking Act Regulations (aka Haliburton Loophole) SEC. 322. HYDRAULIC FRACTURING is amended to read as follows:

(1) UNDERGROUND INJECTION

(A) means the subsurface emplacement of fluids by well injection; and

(B) EXCLUDES

(ii) the underground injection of fluids or propping agents (other than

diesel fuels) pursuant to hydraulic fracturing operations related to oil,

gas, or geothermal production activities.

• Class II wells – Salt Water Disposal (SWD) wells

Injection Well Classification: EPA

• Class I hazardous wastes, industrial non-hazardous liquids, or municipal wastewater. 680 wells

• Class II brines and other fluids associated with oil and gas production, and hydrocarbons for storage. 172,068 wells

• Class III solution mining of minerals. 22,131 wells

• Class IV hazardous or radioactive wastes into or above USDWs. 33 sites

• Class V All injection wells not included in Classes I-IV, non-hazardous fluids into or above USDWs. 400,000 to 650,000 wells

• Class VI Geologic Sequestration of CO2 6-10 commercial wells expected to come online by 2016.

What are the Actual Risks Associated with Hydraulic Fracturing?

Migration of frack fluids through 1,000s ft of rock along fault or

through confining layer – not likely unless vertical separation is

minimal

Disposal of waste fluids poses greater risks: pits, tanks, pipes,

trucking, injection, treatment, etc. These risks have not been

adequately assessed.

Threat from Abandoned Wells — Breakout

Unknown threat from hydraulic fracturing by deep-well injection of waste fluids

What’s the Risk of Breakout Associated with Abandoned Wells?

• Oil drilling began in earnest in the early 1900s – Records of wells, especially older wells, are often incomplete or absent

– Well construction standards weren’t what they are today

– Structural integrity of older abandoned wells may be compromised

– How many? Estimates vary from less than 10,000 to over 110,000 (orphan and inactive) wells in Texas

• Disposal of hydraulic fracturing waste fluids by >12,000 disposal wells in Texas – RRC requires notification of all occurrences of breakout, but doesn’t

maintain a single database

– RRC retains records on breakout for only two years

– There are documented cases where breakout resulted in disposal fluid discharge above ground

– In absence of a centralized database, risk is unknown, but possible

Well Casing Corrosion and Cement Failure

Holes from Corrosion

Cement Failure • Formation damage during drilling (caving) • Casing centralization (incomplete cementing) • Non-adequate drilling mud removal • Incomplete cement placements (pockets) • Inadequate cement-formation/cement casing bond • Cement shrinkage • Contamination of cement by mud or formation fluid • Filtration of the cement slurry • Fracture formation with cement

Casing Failure • Sweet corrosion (CO2

corrosion) • Sour corrosion (H2S corrosion) • Oxygen corrosion • Galvanic corrosion • Crevice corrosion • Erosion corrosion • Microbiologically induced

corrosion

Geriatric Wells and Well Fields

Waste fluids can be flowback, produced

water, or oil/gas products.

This of particular concern when:

• Field is old

• H2S is present

• Field is still active, continued water flood

• Close to disposal wells

At What Distance are Abandoned Wells a Threat?

Disposal Well Permit Regulation (Texas)

Predicated on Isotropic Media

… the applicant shall review … wells that penetrate the proposed disposal zone within a 1/4 mile radius of the proposed disposal well to determine if all abandoned wells have been plugged in a manner that will prevent the movement of fluids from the disposal zone into freshwater strata.

This regulation assumes radial flow and does not account for natural heterogeneity present in geologic media.

How are injected fluids assumed to flow?

Homogeneous and Isotropic Injection Plume Geometry and Size

Plume radius for 50,000 barrels of injection for

formation thicknesses of 300 and 600 ft and

effective porosities of 5%, under homogeneous

and isotropic conditions.

Uniform growth of injection plume under

homogeneous and isotropic conditions.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 5 10 15 20

Rad

ius

of

Inje

cte

d P

lum

e (

ft)

Years After Start of Injection

300’ injected horizon

600’ injected horizon

¼ mile radius

How do injected fluids actually flow?

Geologic Structure Induced Preferential Flow

Injected fluids tend to follow geologic structure and

in situ stress instead of an isotropic sphere or cylinder

An injection well has greater influence

in the direction of maximum horizontal stress and major faults and fractures

Damage due to Tensile Failure Damage due to Compressive/Shear failure

Analyses Provide Indication of How Injected Fluids Actually Flow

Effect of Inclined Layering at depth of 3 km (~9,800 ft)

Mechanical stratigraphic layering strongly controls damage/strain patterns

Overall damage patterns suggest substantial fracture connectivity across model domain

Examples of Breakout from Injection Wells

Example 1 Proposed Disposal Well in Oil/Gas Formation

With Abandoned Wells

Area of Interest

Example Disposal Well Complexities

Example of Disposal Well Complexities Proposed Disposal in Former Oil/Gas Field

0 1 2 3 4 0.5

Kilometers

Existing Water Wells

¼-mile radius

Abandoned Wells

Example Disposal Well Complexities

0 1 2 3 4 0.5

Kilometers

Example 2 Proposed Disposal Well in Oil/Gas Formation

With Abandoned Wells

Proposed Disposal Well in Oil/Gas Formation With Abandoned Wells

Location of proposed injection well

Proposed Disposal Well in Oil/Gas Formation With Abandoned Wells

32797 Horizontal Drilled 9/8/1990

Plugged 10/28/1997 Surf. Casing: 0-832 ft

Prod. Casing: 0-5,698 ft Plug depths

1950-2,117 ft 3,148-3,253 ft 5,404-5,500 ft

Open cased hole 5,500 – 6,043 ft

Perf. Zone 5,698-6,300 ft

30487 Drilled 6/4/1976

Plugged 2/20/1986 Surf. Casing: 0-205 ft

Prod. Casing: 0-6,535 ft Plug depths

1450-6,050 ft Open cased hole 6,050 – 6,541 ft

Perf. Zone 6,107-6,445 ft

30488 Drilled unk

Plugged 1/20/1991 Surf. Casing: 0-205 ft

Prod. Casing: 0-6,535 ft Plug depths

3-13 ft 160-350 ft 717-750 ft

1,325-1,198 ft (?) 1,880-2,000 ft 3,050-3,185 ft

Open cased hole 3,185 – 6,516 ft

Perf. Zone 350-351 ft 850-851 ft

1,325-1,326 ft

30665 Drilled 8/26/1976 Plugged 3/25/1983

Surf. Casing: 0-248 ft Prod. Casing: 0-6,584 ft

Plug depths 0-62 ft

148-348 ft 3,150-3,350 ft 5,820-6,020 ft

Open cased hole 6,020 – 6,585 ft

Perf. Zone 6,130-6,150 ft 6,195-6,359 ft

30428 Drilled 4/12/1976 Plugged 3/15/1983

Surf. Casing: 0-222 ft Prod. Casing: 0-6,582 ft

Plug depths 0-10 ft

124-322 ft 3,147-3,345 ft 5,822-6,020 ft

Open cased hole 6,020 – 6,587 ft

Perf. Zone 6,196-6,525 ft

Proposed SWD Injection Horizon

4,500-5,250 ft

½ mile ¼ mile

32682 Pyote SWD Horizontal converted to SWD

Drilled 5/15/1990 Abandoned 1999

Surf. Casing: 0-689 ft Prod. Casing: 0-5,815 ft

Vertical Depth 6,121 ft

Measured Depth 7,709 ft

Base of Usable Fresh Water 3,100

32760 SWD Horizontal converted to SWD

Drilled 7/30/1990 Converted 6/27/1991

Bridge plug set at 5,700 ft Hard bottom at 5,168 ft

Injects into Olmos Original Vertical Depth

6,195 ft Original Measured Depth

8,822 ft

30367 Drilled 2/17/1976 No Record of Plug

Surf. Casing: 0-217 ft Prod. Casing: 0-6,420 ft

SWD Permit 12882 W-14 filed 2/10/09

5,000 bbl/day Amended W-14 filed 6/15/11

20,000 bbl/day denied Injection intervals

4,580-4,700 ft San Miguel 5,100 – 5,160 ft Olmos

Austin Chalk

Anacacho

San Miguel

Olmos

6000 ft

5620 ft

5180 ft

4530 ft

2000 ft

Wilcox

1000 ft

Carrizo

Ground Level

Escondidio

Midway 3100-3,225 ft

Bigford-Queen City

3500 ft

800 ft

(Not to scale)

Fresh Water

Fresh Water

< ¼ mile

Surface Casing

Plug

¼ mile

Originally Constructed as Horizontal Well s

?

?

Proposed Disposal Well in Oil/Gas Formation With Abandoned Wells

Example 3 Existing Disposal Well

Breakout in an Abandoned, Plugged Well

Surface Breakout from Disposal Well

Operating Disposal

Well

Breakout occurred after 2 years of injection in an abandoned

(and plugged) dry-hole oil well located slightly over ¼ mile away

Industry needs to understand there is a trade off between short-term savings gained from employing outdated management practices in the disposal of fracking waste fluids and long-term liability.

Only by understanding the true, real costs of these decisions will industry change their practices.

Evaluation of the costs are necessary to make a strong case to update liquid waste management practices.

Critical Evaluation Need

Actions to Mitigate Risk

There are several actions that can be taken to mitigate the threat of contamination due to “breakout” from a disposal well.

– Accurately examine and document locations and depths of disposal wells and all nearby existing wells.

– Limit or prohibit injection of liquid wastes into formerly productive horizons (not EOR). That’s where the abandoned wells are more likely to be located.

– Increase the ¼-mile radial distance from proposed disposal well over which abandoned wells are searched.

– Develop a single database for all occurrences of “breakout”. Risk from breakout can only be assessed if number of occurrences and their severity are known.

Contact Information

Ronald T. Green, Ph.D., P.G.

Institute Scientist

Geosciences and Engineering Division

Southwest Research Institute

6220 Culebra

San Antonio, Texas 78238

1.210.522.5305 (office)

1.210.522.5184 (fax)

1.210.316.9242 (cell)

rgreen@swri.edu