Mineral Reactions in Shale Gas Reservoirs: Barite Scale Formation

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Mineral Reactions in Shale Gas Reservoirs: Barite scale formation from reusing produced water as hydraulic fracturing fluid Amelia N. Paukert Vankeuren, J. Alexandra Hakala, Karl Jarvis, and Johnathan E. Moore Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.7b01979 • Publication Date (Web): 19 Jul 2017 Downloaded from http://pubs.acs.org on July 27, 2017

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Environmental Science & Technology

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Mineral reactions in shale gas reservoirs: barite scale formation from reusing produced water as

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hydraulic fracturing fluid

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Amelia N. Paukert Vankeuren* a,b, J. Alexandra Hakala b, Karl Jarvis c,d, Johnathan E. Moore c,d

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a

Geology Department, California State University Sacramento, Sacramento, CA 95819

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b

National Energy Technology Laboratory, U.S. Department of Energy, Pittsburgh, PA 15236

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c

National Energy Technology Laboratory, U.S. Department of Energy, Morgantown, WV 26507

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d

AECOM, Morgantown, WV 26507

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*Corresponding author contact information: Mailing address: California State University,

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Sacramento; 6000 J Street, PLR 1016; Sacramento, CA 95819-6043; Phone: (916) 278-7385;

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Fax: (916) 278-4650; Email: [email protected]

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Abstract

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Hydraulic fracturing for gas production is now ubiquitous in shale plays, but relatively little is

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known about shale-hydraulic fracturing fluid (HFF) reactions within the reservoir. To

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investigate reactions during the shut-in period of hydraulic fracturing, experiments were

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conducted flowing different HFFs through fractured Marcellus Shale cores at reservoir

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temperature and pressure (66oC, 20 MPa) for one week. Results indicate HFFs with

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hydrochloric acid cause substantial dissolution of carbonate minerals, as expected, increasing

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effective fracture volume (fracture volume + near-fracture matrix porosity) by 56-65%. HFFs

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with reused produced water composition cause precipitation of secondary minerals, particularly

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barite, decreasing effective fracture volume by 1-3%. Barite precipitation occurs despite the

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presence of antiscalants in experiments with and without shale contact, and is driven in part by

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addition of dissolved sulfate from the decomposition of persulfate breakers in HFF at reservoir

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conditions. The overall effect of mineral changes on the reservoir has yet to be quantified, but the

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significant amount of barite scale formed by HFFs with reused produced water composition

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could reduce effective fracture volume. Further study is required to extrapolate experimental

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results to reservoir-scale, and to explore the effect that mineral changes from HFF interaction

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with shale might have on gas production.

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1. Introduction

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Over the past decade, technological innovations in horizontal drilling and hydraulic fracturing

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have spurred a shale gas boom and made the US the largest natural gas producer globally.1 The

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Marcellus Shale, which underlies parts of Pennsylvania, New York, West Virginia, and Ohio, is

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a key contributor to US natural gas production.2 In Pennsylvania alone, over 9,500

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unconventional wells have been drilled in the past 10 years and annual natural gas production

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has reached over 4.6 trillion cubic feet.3

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The dramatic increase in gas production has led to a commensurate increase in produced

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water – wastewater that is produced at the wellhead as a result of oil and gas production, either

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through flowback of injected hydraulic fracturing fluid (HFF) or formation water from the

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reservoir. There are now over 1.4 billion gallons of produced water generated in Pennsylvania

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each year.4 This water contains high total dissolved solids (TDS) and naturally occurring

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radioactive materials, making it unsuitable for disposal at wastewater treatment plants.5 Other

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states, e.g., Texas, dispose of the vast majority of their produced water through deep subsurface

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injection wells, but Pennsylvania has only 8 active injection wells for the disposal of oil and gas

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produced water.6-8 Some produced water from Pennsylvania is trucked to disposal wells in West

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Virginia and Ohio, but that carries high costs and additional risks associated with the transport of

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large volumes of wastewater.9-10 Due to the limited options for disposal of produced water in

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Pennsylvania, most produced water is now diluted with freshwater and reused as HFF.9, 11-13

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Reusing produced water as HFF introduces another complication – the high concentration of

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alkali earth metals (calcium, barium, strontium) in produced water could lead to scale

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formation.14-17 Precipitation of scale minerals could result in local reductions in reservoir

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porosity and fracture aperture, preventing gas from reaching the wellbore.16, 18 The potential for

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scale minerals to damage well productivity is well-recognized by the industry, and antiscalants

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are usually included in the HFF chemical mixture.19 However, recent experiments have shown

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antiscalants are ineffective at preventing precipitation of common scaling minerals (e.g., barite,

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calcite) under supersaturated conditions.20-22 Given the high concentrations of alkali earth metals

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in produced water,13, 23 mixing produced water with freshwater and HFF chemicals that generate

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sulfate may cause supersaturation and precipitation of scaling minerals. Interaction between HFF

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and shale minerals could also change the fluid composition (e.g., increasing dissolved sulfate

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through pyrite oxidation) and lead to mineral scaling.

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The most likely timeframe for scale mineral formation related to HFF is during injection–

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when the fluid temperature rises from ambient to reservoir temperature– and the shut-in

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(soaking) period– the days to month timeframe after hydraulic fracturing but before well

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production when HFF sits in contact with the shale with little to no flow. What happens to the

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fluid during the shut-in period is not well understood, and the relationship between well

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productivity and length of the shut-in period is debated.24-25 While fluid imbibition into shale

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during the shut-in period has been examined as a mechanism for reduced well productivity,26

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geochemical processes such as mineral reactions within the shale reservoir could also impact gas

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production.

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Though common mineral reactions have been well characterized in the lab, these

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experiments are typically done in isolation with an emphasis on a particular reaction (e.g., calcite

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dissolution or barite precipitation). Interactions between the complex mixture of solutes and

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chemical additives present in HFF may alter mineral behavior and yield results that do not match

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those predicted from laboratory studies. Thus it is important to conduct experiments in the lab

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that use the complex mixtures employed in the field.

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Prior experiments suggest that mineral reactions due to shale-fluid interaction could be

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significant. Studies evaluating reactions between water with and without HFF chemicals and

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various shales at ambient pressure and temperature have shown evidence of dissolution of

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carbonate minerals and iron and manganese oxides, and precipitation of sulfate minerals.27-29 At

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elevated temperature (80oC), under oxidizing conditions such as those created by the exposure to

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the atmosphere and/or inclusion of an oxidant breaker in the HFF chemicals (typically

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ammonium persulfate)30 these experiments showed evidence of pyrite oxidation, and

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precipitation of iron oxides and sometimes barite.27, 29, 31 High temperature, high pressure rocking

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autoclave experiments reacting Marcellus Shale with synthetic shale formation brine mixed with

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HFF chemicals or synthetic diluted produced water also exhibited carbonate mineral dissolution

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and minor anhydrite or gypsum precipitation, and predicted precipitation of barite and nontronite

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clay.32-33 The formation of barite scale in relation to shale gas wells has been investigated in

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experiments performed at ambient pressure and temperature, including interactions with

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antiscalants and using abandoned mine drainage to remove barium from HFF.34-35

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All prior experiments have utilized shale powder and/or rock chips in benchtop or batch

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reactor settings, precluding evaluation of spatial differences along a flow path and resulting in a

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fluid:rock ratio much higher than expected in shale reservoirs. Most experiments were conducted

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at ambient temperature and pressure, far from the conditions found in shale reservoirs. While

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these experiments provide valuable preliminary data on mineral reactions in shale reservoirs,

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there is a need for fractured core flow experiments at reservoir temperature and pressure to more

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closely approximate conditions in the field.

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To explore mineral reactions within the shale reservoir during the shut-in period and related

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effects on gas production, fractured core flooding experiments were conducted exposing shale to

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different compositions of HFF at reservoir temperature and pressure conditions. This study aims

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to investigate:

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•

What mineral reactions result from HFF injection into a shale reservoir?

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•

What mineral reactions result from varying HFF composition?

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•

What effect do these reactions have on fracture volume, and how might that affect well

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productivity?

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2. Experimental method

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Experiments were conducted exposing Marcellus Shale cores to synthetic HFFs of varying

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compositions for 7 days. Changes to fluid chemistry and shale fracture surfaces were used to

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determine dissolution and secondary mineral precipitation reactions resulting from fluid-rock

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interaction. Experiments were designed to closely approximate conditions in the field during

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hydraulic fracturing. Pressure and temperature were set to those expected at a depth of 6,600 ft,

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where the Marcellus Shale occurs in southwestern Pennsylvania (Table 1). Oxygen was limited

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in fluids by degassing fluids in a vacuum chamber and then flushing the headspace above HFF

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with nitrogen gas to prevent addition of dissolved oxygen, but oxygen was not entirely removed

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from the fluid prior to injection because the vast majority of operators do not incorporate oxygen

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scavengers in their HFF.19 Because these experiments are intended to simulate the shut-in period,

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the flow rate was set as slow as possible while still generating sufficient effluent for analyses.

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The residence time of fluid in these experiments is approximately 100 minutes. While this is

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likely shorter than would be expected during the shut-in period, when neither injection nor

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production is occurring, it is a reasonable approximation of prolonged contact between shale and

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HFF. For comparison, during hydraulic fracturing our industry collaborator reported average

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fluid injection rates of 12,000-17,500 liters/min, and residence time is estimated at 0.5-0.8

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minutes.36

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Table 1: Experimental parameters Temperature 65.5oC Pore pressure

20 MPa

Confining pressure

21.4 MPa

Headspace

High purity N2 gas

Fluids tested

1) SW: local spring water (Table S1) 2) SWF: local spring water with HFF chemicals added (Table S2) 2) PW: synthetic reused produced water (Table S3) 3) PWF: synthetic reused produced water with HFF chemicals added 4) PWFNA: synthetic reused produced water with HFF chemicals added, excluding hydrochloric acid (HCl)

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Fluid flow rate

0.04 ml/min

Dimensions of material

Length 152.4 mm

in core holder

Diameter 38.1 mm Shale experiments

Control experiments

Duration

7 days

2 days

Fluid sampling interval

2 days, 7 days

2 days

Material in core holder a

Marcellus shale: 46.5% clay (32.5% illite, 7%

316 stainless

illite-smectite, 7% chlorite), 23.3% calcite,

steel cylindrical

18.6% quartz, 4.6% pyrite, 7% organic content

spacers

174 x 103 mm3

N/A

Shale volume

Average fracture volume 3927 mm3

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Estimated fracture

>210 µm based on minimum proppant grain size, N/A

aperture b

500-1,500 µm based on x-ray CT imaging

Proppant composition c

40/70 mesh northern white sand (>99% SiO2)

a

b

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Average shale mineralogical composition in percent mineral content from 37, average shale

It was not possible to measure fracture aperture at experimental pressure. Aperture is estimated from x-ray CT images taken at ambient pressure.

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c

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2.1 Fluid compositions

130 131

N/A

organic content from 38

125 126

N/A

Unimin Energy Solutions, The Woodlands, TX

All five experimental fluids (Table 1) used local spring water as the base fluid to ensure a common starting point and to match the fresh water used in industrial hydraulic fracturing

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operations. Synthetic reused produced water was generated by adding salts to spring water to

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simulate the composition of HFF using diluted reused produced water from a well drilled in the

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Marcellus Shale in Greene County, PA that was provided by an industry collaborator (Table

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S3).39 The compositions of HFF from other wells targeting the same reservoir have been reported

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and discussed in a previous publication.40 HFF chemicals were chosen to represent an average

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HFF composition used in western Pennsylvania and eastern Ohio, collated from numerous

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reports found on FracFocus.org.41-43 The selected HFF chemicals included a gelling agent, scale

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inhibitor, corrosion inhibitor, clay stabilizer, iron control, friction reducer, cross linker, breaker,

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surfactant, pH adjusters, and biocide. Two fluids also included HCl because HCl is usually

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injected into a well prior to hydraulic fracturing to clean perforations and allow HFF access to

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the shale (a step known as the acid pack). Because acid injection precedes injection of HFF,

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PWFNA may be most representative of conditions within the shale reservoir at the time of

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hydraulic fracturing. However, the acid neutralizing capacity of the shale will depend on the

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amount of carbonate minerals accessible to dissolve and buffer the pH, will vary by shale

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formation and by location within the formation. While it is possible that all acid is spent prior to

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fracturing, it is also possible that some acid remains. Operators generally do not take samples of

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fluid from the borehole after acid injection but prior to fracturing, so there are no data to

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constrain the pH of the fluid in the well prior to fracturing. Due to this uncertainty, experiments

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were run for both end-member cases: with HCl, as if no acid were spent resulting in pH ~2, and

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without HCl, as if all acid were spent, resulting in pH ~8. The complicated mixture in HFF

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contains many compounds that could– and in some cases are intended to– affect mineral

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reactions, making it exceedingly difficult to predict mineral behavior within the reservoir.

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2.2 Experimental set up

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A system was constructed to simulate HFF injection into a shale reservoir and subsequent

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reaction between fluids and shale minerals (Table 1, Fig S1).

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For each fluid, a control experiment was conducted in which the fluid flowed through a core

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holder containing stainless steel spacers rather than shale at experimental temperature and

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pressure. These control experiments allowed the differentiation between reactions that result

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from heating and pressurizing the HFF and reactions that result from fluid-shale interaction. For

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shale experiments, effluent was collected in the syringe pump reservoirs and sampled after 2

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days (2-day samples), representing an average of effluent from 0-2 days, and again after 7 days

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(7-day samples), representing an average of effluent from 2-7 days. Detailed experimental

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protocols are provided in the supporting information.

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2.3 Shale core preparation:

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Cores were cut from the interior of large Marcellus Shale samples taken from outcrops away

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from the weathered surface, artificially fractured using the Brazilian method 44 (Hydrasplit

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Masonry Stone Splitter CM-10, Park Industries, St. Cloud, MN). Fractures were packed with

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proppant to maintain a propped fracture at experimental pressure and simulate the nature of the

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fracture once proppant has been emplaced and fluid pressure is reduced. The mineralogy of the

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shale exposed along each fracture face varies slightly, but is assumed to be representative of an

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average Marcellus Shale composition. Scanning electron microscopy with energy dispersive x-

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ray spectroscopy (SEM/EDS; Quanta 600 FEG, FEI, Hillsboro, OR) supports this assumption

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(Fig. S1).

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2.4 Analytical methods:

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Before and after experiments, SEM/EDS analyses were performed on shale fracture faces, and x-

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ray computed tomography (CT) with 24 µm pixel resolution (M5000 Industrial Computed

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Tomography System, North Star Imaging, Rogers, MN) was performed on select core sections:

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the quarter lengths of core nearest the fluid inlet and outlet (hereafter referred to as the inlet

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38mm and outlet 38mm, respectively) (Fig S3). Images were processed with ImageJ.45

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For experiments where CT scans showed significant mineral changes at the conclusion of the

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experiments, analyses included segmentation of the CT images using ilastik, an interactive

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segmentation toolkit.46 The pixel classification workflow was used to differentiate between

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specific components: matrix shale, proppant grains, open fracture, mineral dissolution, and

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secondary mineral precipitation, where applicable.

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Fluid chemistry was measured for all fluid samples (see supporting information for detailed

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analytical methods). The complicated composition of HFFs required special treatment to analyze

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via instruments using inductively coupled plasma, which is discussed in the supporting

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information. All but a few samples have charge balances within +4% electroneutrality, and all

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samples are within +20%.

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3. Results and discussion

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The most significant mineral changes observed during experiments were calcite dissolution and

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barite precipitation. Fluid chemistry data and plots of significant changes are provided in the

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supporting information (Table S5a and S5b, Fig S2). Fluid chemistry data were speciated and

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saturation indices calculated (SI = log Q/K, where Q is the ion activity product and K is the

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equilibrium constant) with PHREEQC v3.2 using the LLNL thermodynamic database at 65.5oC

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and 0.101 MPa (Table S6).47

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Volume changes due to mineral reactions were calculated when quantifiable at CT scan

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resolution (i.e., for the inlet 38 mm of core for experiments with HFF chemicals) (Table 2).

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Spatial variations in volume changes are depicted in 3-D web enhanced objects highlighting

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initial fracture volume (yellow), matrix porosity added by dissolution (green), effective fracture

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volume lost by secondary mineral precipitation (white), and quartz proppant (red) (WEO 1-3).

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Effective fracture volume (defined for this paper as fracture volume + near-fracture matrix

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porosity) changes are estimates; cores were depressurized and moved to the CT scanner, so shale

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cores may have shifted slightly in the core sleeves, preventing the direct comparison of core

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locations before and after the experiments. Additionally, initial fracture volumes are maximum

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values because CT scans were performed at 0.101 MPa, while experiments were conducted at 20

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MPa pore pressure, 21.4 MPa confining pressure. Mineral changes in the outlet 38 mm were

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below pixel resolution and could not be quantified. All x-ray CT images are provided (Fig S3

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and S4) but only results from the inlet 38 mm of core are discussed.

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3.1 Experiments with natural spring water

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Fluid chemistry

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Both SW and SWF experiments show an increase in pH, Ca2+, and dissolved inorganic

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carbon (DIC) in the effluent with respect to the influent (Table S5, Figure S2), though changes

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are more pronounced in SWF experiments due to the much lower starting pH. In 2-day samples,

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the increase in Ca2+ in the SWF experiments is over 12 times the increase in the SW experiments.

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Dissolution of calcite likely is responsible for both pH buffering and the release of Ca2+ and DIC

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from the shale into the fluid. In SWF, the increase in DIC is not stoichiometric with Ca2+

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because DIC in the sample is likely an underestimate. Samples were exposed to the atmosphere

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during sampling, and given the low pH of the solutions, much of the DIC should have been in the

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form of carbonic acid and may have been lost by degassing of CO2. Nonetheless, calcite

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dissolution is supported by saturation indices (Table S6): SW-influent and SWF-influent are

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highly undersaturated with respect to calcite (SI of -6 and -11, respectively) and after 7 days of

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contact with shale, saturation indices in the effluents are much closer to calcite equilibrium (SI of

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-1 and 1, respectively).

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Sulfate also increased in 2 day-samples with respect to the influents for both SW and

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SWF experiments, with the increase 2.5 times larger in SWF experiments (Table S5b). With SW,

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control experiments show little increase in SO42- compared to the experiments contacting shale.

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This implies that the increase in SO42- when shale reacts with fresh water is likely due to

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oxidation of pyrite, something observed in prior studies on HFF-shale reactions, even – to a

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limited extent – under anoxic conditions.27, 29, 32 In SWF experiments, SO42- concentration

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increases even in the control experiment due to thermal activation of ammonium persulfate in the

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HFF chemicals to produce sulfate ions.48 In both the SW and SWF experiments, SO42- in 7-day

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samples decreased slightly with respect to the 2-day samples. In SW experiments, though

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gypsum remains undersaturated in fluid samples (SI -1.7 to -2.3), the increased Ca2+ from calcite

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dissolution and SO42- from pyrite oxidation caused local oversaturation and precipitation of

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gypsum, thus lowering dissolved SO42- between days 2 and 7. In SWF experiments, the larger

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increase in SO42- from HFF chemicals may have allowed the formation of both barite and

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gypsum and corresponding reductions in SO42-. Though one would expect the concentration of

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sulfate to reach equilibrium with respect to barite and then remain at that concentration, there

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may have been temporary oversaturation due to the rate of SO42- release by persulfate

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decomposition exceeding the rate of removal by barite precipitation. Saturation indices for barite

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are at equilibrium or moderately oversaturated throughout the experiments (SI of 0 to 0.4). Barite

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precipitation dynamics are discussed in more detail following the experimental results.

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In both SW and SWF experiments, small increases (up to 0.15 mmol/L) in Mg2+, Na+, SiO2, and Cl- are also observed. Na+ and Cl- increases may be due to dissolution of halite or

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saline pore water from the shale, and Mg2+ and SiO2 from dissolution of dolomite and clay,

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respectively.

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Fracture surface imaging

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SW experiments: SEM analysis reveals dissolution of calcium carbonate minerals near the fluid

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inlet, and minor precipitation of iron oxides and gypsum near the outlet (Fig S3). Gypsum seems

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to have preferentially precipitated on top of primary pyrite (Fig S3). Also near the outlet, new

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Mg-Al-rich minerals appear, which could be due to precipitation or deflocculation and transport

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of clays from closer to the inlet. SW experiments were the only ones showing new Mg-Al-rich

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minerals; the low salinity of the spring water may be responsible for deflocculation of clays in

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the shale.49

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X-ray CT images do not show visible alteration to the shale (Fig S3) because changes in

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mineral volumes are below the 24 µm pixel resolution. This prevents calculation of effective

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fracture volume change using ilastik for these experiments.

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SWF experiments: X-ray CT images from SWF experiments show a darkened reaction rim of

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calcite dissolution extending along the surface of the main fracture from the fluid inlet to a

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distance at least 30 mm along the core and penetrating a maximum of 0.8 mm into the shale (Fig

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1). SEM images of the fracture surface confirm that extensive dissolution of calcite has occurred

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in this area. When a dense grouping of proppant is present along part of the fracture, the reaction

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rim is often narrower near the proppant than elsewhere along the fracture (Fig S3). Clusters of

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proppant are thought to slow the flow of fluid, forcing most of the fluid through the open fracture.

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Dissolution is faster along preferential pathways due to the greater availability of low pH

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reactive fluid.50-52 Additionally, x-ray CT images reveal the presence of a secondary material less

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dense than the shale, SEM images indicate that this is amorphous and may be residue of HFF

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chemicals, such as guar gum (Fig S5). This residue is not seen in experiments with reused

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produced water and HFF chemicals, possibly due to decreased stability of guar gum with the

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higher concentration of Na+. Studies testing the performance of guar based gelling agents in

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reused produced water showed significantly decreased viscosity at levels of 85 mmol/L Na+; the

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concentration of Na+ in HFF with reused produced water composition is 3.5 times that value.53

275 276

Figure 1: SWF experiments. A) and B) x-ray CT of inlet 38mm of shale parallel to flow, B) with

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calcite dissolution (dark gray) along fracture. The decrease in fracture aperture in B is likely due

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to the core halves shifting in the core sleeve during the experiment, not precipitation or

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geomechanical alteration. C) and D) SEM of main fracture face near the fluid inlet, D) with

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calcite dissolution (dark holes)

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X-ray CT analysis indicates a significant increase in effective fracture volume (WEO 1).

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In the inlet 38 mm, calcite dissolution in shale adjacent to the fracture creates matrix porosity,

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increasing effective fracture volume by 65%. The amorphous secondary material thought to be

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HFF chemical residue fills 4% of the fracture volume, yielding a net increase of 61%. For the

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outlet 38 mm, there was no measurable change in effective fracture volume on the x-ray CT, so

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the impact of calcite dissolution on effective fracture volume appears to only apply to areas that

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are exposed to HFF with residual acid.

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3.2 Experiments with synthetic reused produced water

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Fluid chemistry

290

All fluids with a reused produced water base have high TDS, so subtle changes in solute

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concentration relative to the influents may not be perceptible. In PW and PWF experiments, pH

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and DIC both increase due to dissolution of carbonate minerals. PW experiments have only

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minor dissolution, causing a slight increase in DIC and no measurable change in Ca2+. PWF

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experiments have a much more dramatic increase in pH, Ca2+, and DIC due to the lower starting

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pH. Again, DIC measurements in these samples are likely underestimates due exposure to the

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atmosphere during sampling. In both sets of experiments, PW and PWF, influents are

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undersaturated with respect to calcite (SI of -0.03 and -13, respectively) and saturation index

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increases in the 7-day samples (SI of 1 and -0.3, respectively) due to calcite dissolution.

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PWFNA experiments show a decrease in pH and DIC due to precipitation of calcite.

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PWFNA starts off oversaturated with respect to calcite (SI of 1.9) and draws closer to

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equilibrium in the 7-day samples (SI of 1.3). Precipitation of calcite in the control experiment

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may have occurred due to the increased temperature in the core holder lowering calcite solubility.

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PW at 20oC is undersaturated with respect to calcite (SI of -0.65), while the same fluid at 66oC is

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oversaturated (SI of 1.9).

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All three experiments, PW, PWF, and PWFNA show decreases in Ba2+ in control

306

experiments, suggesting some barite precipitation occurs from the fluid even without interaction

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with the shale. In experiments containing HFF chemicals (PWF and PWFNA) with or without

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shale, the magnitude of Ba2+ decrease in 2-day samples relative to the influents is 2-8 times the

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decrease in the experiment without HFF chemicals. The greater decrease in Ba2+ is due to barite

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precipitation driven by the addition of SO42- from activation of ammonium persulfate in the HFF

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chemicals. In PW experiments, though Ba2+ decreases, SO42- increases in experiments with shale

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cores so it is likely that SO42- removal from the fluid by barite precipitation is more than

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balanced by addition of SO42- from pyrite oxidation.

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Fracture surface imaging

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PW experiments: Changes in fracture volume in x-ray CT images along the main fracture for the

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PW experiment are below the 24 µm resolution, preventing quantification of fracture volume

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change (Fig S4). However, a small side fracture does exhibit mineralization (Fig 2). SEM/EDS

318

of that location reveals the minerals filling the fracture to be a combination of barite and gypsum.

319

SEM images of the shale fracture surface near the inlet show dissolution of carbonate minerals,

320

but farther from the inlet, calcite dissolution ceases. SEM images also show precipitated barite

321

and gypsum at the inlet of the core. In some areas, the gypsum contains significant amounts of

322

strontium. These results are similar to previous experiments exposing samples of Marcellus

323

Shale to synthetic reused produced water at reservoir conditions.33

16


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324 325

Figure 2: PW experiments. A) and B) x-ray CT of shale perpendicular to flow, near fluid outlet,

326

B) with small fracture filled by secondary mineral precipitation. C) and D) SEM images of

327

fracture in B), partially filled with barite and gypsum.

328

PWF experiments: X-ray CT imaging and SEM analysis confirm the extensive dissolution of

329

calcite and precipitation of barite suggested by the fluid chemistry. X-ray CT imaging shows a

330

very bright, dense mineral lining the innermost surface of the main fracture from the inlet to a

331

distance of about 3 mm down the core, and SEM/EDS confirms this is a Ba-S mineral (hereafter,

332

Ba-S minerals are assumed to be barite) (Fig 3). X-ray CT also shows a darker, less dense rim

333

between the barite and unaltered shale extending for the inlet 38 mm; SEM/EDS identifies this as

334

calcite dissolution. In some instances, barite crystals grew into the space vacated by the dissolved

335

calcite (Fig 3). SEM/EDS imaging also shows an amorphous Ca-rich deposit that is interspersed

336

with the barite crystals near the fluid inlet. EDS analysis of the deposit rules out gypsum (no S)

337

and calcite is unlikely given the low pH of the fluid, so the exact composition has yet to be

338

identified. At the inlet, where the fluid first meets the core, x-ray CT and SEM/EDS show barite

17



339

precipitated in the shape of the fluid distributor (Fig 3), suggesting considerable precipitation of

340

barite upon entry into the core holder. Similar to SWF, x-ray CT images show that when dense

341

groupings of proppant are present, mineral reactions (barite precipitation and calcite dissolution)

342

are more pronounced along open areas of the fracture, the preferred fluid pathway.

343

X-ray CT analysis indicates a net effect fracture volume increase of 55% due to extensive

344

dissolution of calcite in the shale matrix along the fracture (WEO 2). Barite precipitation near the

345

fluid inlet produces a slight decrease in effective fracture volume (1%), but that was more than

346

compensated for by calcite dissolution.

347

PWFNA experiments: There is a visible white coating on the shale fracture surface extending the

348

length of the shale core, though it is concentrated near the fluid inlet (Fig S6). SEM/EDS

349

confirms this is barite. X-ray CT scans show that in addition to precipitating along the main

350

fracture, secondary minerals (presumably barite) filled portions of smaller side fractures.

351

SEM/EDS and x-ray CT show barite precipitated extensively near the fluid inlet, again in the

352

shape of the flow distributor, and filled small fractures at the inlet (Fig 3). Barite also cemented

353

some proppant grains to the fracture face.

354

X-ray CT analysis for these experiments exhibited a net decrease in effective fracture volume

355

(WEO 3). The lack of calcite dissolution meant there was no mechanism for increasing effective

356

fracture volume, while barite precipitation decreased fracture volume by 2%.

357

The barite precipitated in this experiment exhibits many different morphologies (Fig S6). At the

358

inlet of the core, barite forms in both rounded and sharp tabular shapes, sometimes clustering

359

together in masses and sometimes as isolated crystals. In the inlet 38 mm, some of the barite has

360

a more porous look, while other barite crystals are much smaller and more angular. The reasons

361

for this are discussed in the next section.

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362


Table 2: Summary of experimental findings for the five different fluids tested. Experimental ID Fluid composition

SW

PW2

SWF2

PWF2

PWFNA2

Spring water

Diluted

Spring water

Diluted

Diluted

produced

with HFF

produced water

produced

water

chemicals

with HFF

water with

chemicals and

HFF

HCl

chemicals

Influent pH

5.1

7.2

1.7

2.0

8.2

Ending pH

7.0

7.9

7.2

6.0

7.4

Starting SI Calcite

-5.9

0.0

-12.8

-10.6

1.9

Ending SI Calcite

-1.0

0.9

1.0

-0.3

1.2

Starting SI Barite

-1.0

0.0

0.4

1.6

1.9

Ending SI Barite

-0.9

0.4

0.4

0.6

1.0

Starting SI Gypsum

-4.1

-3.4

-4.0

-1.8

-1.4

Ending SI Gypsum

-2.3

-2.9

-0.8

-1.9

-1.9

Changes apparent

Calcite

Minor

Calcite

Calcite

Barite and

dissolution,

calcite

dissolution,

dissolution,

minor calcite

gypsum

dissolution,

HFF

barite and

precipitation

precipitation,

barite and

chemical

amorphous Ca-

clay transport

gypsum

residue,

rich

precipitation

minor barite

precipitation

along shale fracture face

precipitation Initial fracture volume (mm3) a

661

1068

1216

Fracture volume lost to secondary mineral

N/A

12

29

19



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precipitation (mm3) Fracture volume lost to secondary amorphous material (HFF chemical residue) (mm3)

24

N/A

N/A

(mm3)

430

601

N/A

Net effective fracture volume change (mm3)

406

589

-29

Net effective fracture volume change (%)

61%

55%

-2%

Matrix porosity added by mineral dissolution

363

a

364

volume changes were quantifiable at x-ray CT resolution (24 µm).

Volume changes were only calculated for the first 38mm of core from the fluid inlet, where

365

20


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366

Figure 3: A-F) PWF and G-

367

L) PWFNA experiments. A-

368

B), and G-H) X-ray CT of

369

inlet 38mm of shale parallel

370

to flow. B) and H) bright

371

spots indicate barite

372

precipitation, and B)

373

darkening indicates calcite

374

dissolution along fracture.

375

C-D) and I-J) X-ray CT of

376

shale perpendicular to flow

377

near fluid inlet. D) and I)

378

with barite densely

379

precipitated in the shape of

380

the flow distributor (M). D) shows pitting from calcite dissolution (3 long dark lines are for core orientation). E) SEM of the fracture

381

parallel to flow with secondary barite in void space created by calcite vein dissolution, and F) close-up of minerals in E). K) and L)

382

SEM of secondary barite filling fractures in J).

21



383

3.3 Controls on barite precipitation:

384

Barite precipitation occurred in all experiments with synthetic reused produced water. In

385

experiments with produced water and HFF chemicals, dense barite precipitation occurred near

386

the core inlet. At salinities up to those found in these experiments, barite solubility increases with

387

pressure and temperature up to about 150oC, so as the fluid enters the core holder, the solubility

388

should increase.54 There are several potentially complimentary hypotheses for elevated barite

389

precipitation near the fluid inlet: the thermal activation of persulfate in HFF chemicals may add

390

SO42- and increase saturation index with respect to barite, scale inhibitor performance may

391

degrade due to increased temperature and low pH, and the temperature increase may affect

392

nucleation and precipitation kinetics.

393

Effect of temperature

394

Scale inhibitors are less effective at preventing barite precipitation at higher temperature.

395

Previous investigations evaluated barite precipitation from supersaturated solutions with scale

396

inhibitors and found that induction time (time until barite begins to nucleate) in the presence of

397

phosphonate and polycarboxonate scale inhibitors is 10-100 times shorter at temperatures of 50-

398

70oC than at 25oC.55 That temperature swing is similar to the one in this study: when fluid enters

399

the heated core holder the temperature increases from ambient (20oC) to reservoir (65.5oC).

400

Though these experiments utilized a different scale inhibitor (ethylene glycol), it appears the

401

efficacy may have been similarly reduced by increased fluid temperature. Heating of the HFF

402

chemicals also increased dissolved SO42-. Persulfates, which are often included in HFF to

403

decompose gelling agents and decrease fluid viscosity, are activated by heat (50-70oC), acidic

404

pH, and transition metals – all of which may be present during hydraulic fracturing.48, 56 When

405

activated, the persulfate (S2O82-) degrades into sulfate radicals (SO4-) that then act as oxidizers

22


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406

and produce sulfate (SO42-) as a byproduct of the oxidation reaction. The addition of dissolved

407

sulfate from HFF chemicals is supported by the fact that SO42- increases 1.25 mmol/L in SWF

408

control experiments. The degradation of ammonium persulfate in SWF-influent (0.02 wt %)

409

could supply up to 1.8 mmol/L SO42-.

410

Further evidence of SO42- release from persulfate activation is found in the PWF and

411

PWFNA control experiments. In produced water experiments, the presence of Ba2+ and

412

consequent ability to remove SO42- from solution through barite precipitation makes it

413

impossible to directly measure SO42- increase. However, Ba2+ can be used as a proxy for SO42-.

414

In the PWF control experiment, dissolved Ba2+ decreased by 1.4 mmol/L. If this decrease is

415

driven solely by barite precipitation – which is likely since the low pH precludes formation of

416

barium carbonates – it requires a stoichiometric SO42- decrease. However, PWF influent only

417

contains 0.5 mmol/L SO42-. Given that there was no shale core present in the control, the 0.9

418

mmol/L SO42- difference between what was present in the influent and what was necessary for

419

barite precipitation must have come from HFF chemical decomposition, likely the ammonium

420

persulfate. The SO42- addition could be critical for barite precipitation in the presence of

421

antiscalants for PWF and PWFNA experiments. Influents for these experiments are already

422

supersaturated with respect to barite (SI of 1.6 and 1.9, respectively), and the addition of up to

423

1.8 mmol/L SO42- would increase supersaturation (SI of 2.2 and 2.4, respectively) to above the

424

threshold at which barite precipitates regardless of the presence of antiscalants.22, 57

425

Finally, barite precipitation near the inlet may be driven by the increase in temperature and

426

corresponding increase in barite nucleation and precipitation kinetics.58-59 Though the

427

temperature increase almost doubles barite solubility, from 0.04 to 0.075 mmol BaSO4/kg

428

water,54 the lowest concentration of Ba2+ and SO42- in all of the experiments with produced water

23



429

(0.18 mmol/kg) remains greater than twice the solubility at 65.5oC. Thus, the increased

430

solubility at higher temperature should not impede barite precipitation. Indeed, increased barite

431

formation at the core inlets in PWF and PWFNA experiments is starkly illustrated by Fig 3. X-

432

ray CT images show barite precipitated in the shape of arcs and triangles matching the shape of

433

the flow distributors. The fluid does not even enter the shale core before barite precipitation

434

begins.

435

Effect of pH

436

The efficacy of scale inhibitors at preventing barite precipitation varies not only with

437

temperature, but also pH. In PWF experiments, barite precipitation was strongly concentrated at

438

the inlet of the core. In PWFNA experiments, while there is a concentrated barite deposit at the

439

core inlet, a thinner layer of barite is distributed throughout the length of the core. The

440

concentration of barite formation near the fluid inlet in the lower pH PWF experiments parallels

441

previous studies on the pH dependence of barite inhibition by phosphonate and polycarboxylate

442

antiscalants; in those experiments at pH

Mineral Reactions in Shale Gas Reservoirs: Barite Scale Formation

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