proppant market overviewspe.tamu.edu/wp-content/uploads/2018/10/proppant_forum_10-2-18.pdfproppant...

Proppant Market OverviewERIK NYSTROMVICE PRESIDENT, STRATEGIC MARKETING

10/1/2018 • 1

WTI forecasts indicate that pricing will remain flat to down

$-

$20

$40

$60

$80

$100

$120WTI Forwards and Projections

WTI average

Estimates2018 E 2019 E

EIA $66 $62

Credit Suisse $66 $65

JP Morgan $62 $58

Simmons PJC $68 $65

Source: FactSet, Market Watch, CNBC

OPEC deal

Failed OPEC

deal

Lifting Iran

Sanctions

Deflation and currency

deleveraging causing

a false start

OPEC announce

leveraged roll-off of cuts

Consensus forecast rangeCurrent WTI estimates are in a tight band for

2019 between $58 and $65, lower than

current traded prices.

This is due to sentiment that demand growth

may not be as robust as forecasted as well

as factoring in the leveraged rolloffs of

OPEC production cuts during the next year.

Actuals Forwards

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18

10/1/2018 • 2

Capacity of drilling rigs has outpaced completion crews

Efficiency calculated using demonstrated capabilities of 1.3 wells per month per rig and 3.1 completions per month per crew

Rig capacity

Completion

Crew Capacity

Rig and Completion Crew Capacity

Source: Internal Estimates, Energent Group, EIA, Baker Hughes

An increase of DUCs is attributed to the industry’s ability to drill much faster than to

complete and indicates the decoupling seen in oil and gas between rigs and production

48.3

6

Total DUC’s across all

Shale Plays

Million tons of

Potential Demand

Months of Backlogged

Completions

8,031

10/1/2018 • 3

Active frac crews by play weighted toward the Permian

164

53

43

42

38

26

34

Bakken

Marcellus

Eagle Ford

HaynesvillePermian

Mid-Con

Rockies

Source: Internal Estimates; current as of April 2018

400Active Frac Crews

operating in the US

14%YTD in 2018

10/1/2018 • 4

Growth in frac crews expected to pause until late 2019

-

50

100

150

200

250

300

350

400

450

500

Jun-16 Dec-16 Jun-17 Dec-17 Jun-18 Dec-18 Jun-19 Dec-19

Active Crew Counts & Projections

Shale PlayTons/mo Per

Crew

Permian 18,000

Marcellus 20,000

Eagle Ford 30,000

MidCon 15,000

Rockies 26,000

Bakken 18,000

Haynesville 15,000

Permian mid-stream constraints are leading to an oversupply of frac crews capping

demand at current levels until expansion projects can be completed in late 2019

Crude oil takeaway capacity constraints leading

to a pause in growth in the Permian until Q4 2019

Permian

Eagle Ford

Marcellus

Mid Con

Rockies

Bakken

Haynesville

Source: Internal Estimates

10/1/2018 • 5

Active frac crews declining across four major shale plays

-

20

40

60

80

100

120

140

160

180

Permian

Eagle Ford

Marcellus

Mid Con

Rockies

Bakken

Haynesville

ForecastActualsPlay Jan 2018 June 2018 Dec 2018

June to

Dec Δ

Permian 148 167 151 (8%)

Eagle Ford 41 51 57 14%

Marcellus 49 56 39 (23%)

MidCon 39 49 33 (22%)

Rockies 25 26 23 (12%)

Bakken 27 31 42 29%

Haynesville 27 31 33 10%

Total US 356 411 389 (5%)

Active frac crews by play in 2018

Crew counts across a number of major

shale plays are in decline due to

stressed pipeline infrastructure and

cash flow conscious E&Ps.


10/1/2018 • 6

Short term outlook indicates ~105 million tons in 2019

Proppant Consumption Forecast (millions of tons)

Shale Play 2016 2017 2018 2019

Permian 12 22 34 33

Eagle Ford 7 12 18 22

Marcellus 6 10 12 11

MidCon 4 7 7 8

Rockies 3 7 8 8

Bakken 3 5 7 9

Haynesville 2 4 6 7

Others 1 2 2 2

Canada 4 6 6 6

Total 42 75 100 108

Range 38 - 46 68 - 83 95 - 105 105 - 115

Pipeline constraints in the Permian will likely lead to growth in

the Eagle Ford while other plays to remain near 2018 levels

Source: Internal Estimates, Energent Group

0

20

40

60

80

100

120

2016 2017 2018 2019

Permian

Eagle Ford

Marcellus

MidCon

Rockies

Bakken

Haynesville

Others (US)Canada

10/1/2018 • 8

Proliferation of in-basin tonnage causing oversupply

0

50

100

150

200

250

4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19

Mill

ion

s o

f To

ns

Northern White

Brady

Permian

Eagle Ford

MidCon

0

20

40

60

80

Supply Demand

0

5

10

15

20

25

30

Supply Demand

0

5

10

15

20

Supply Demand

Permian

MidCon

Eagle Ford

Capacity buildout timeline

Rate of capacity additions from in-basin suppliers is outpacing market

growth. In 2019, the Permian, Eagle Ford and MidCon will contain more

supply then forecasted demand.

2019 Demand

Source: Internal Estimates, Company specific websites

10/1/2018 • 9

WTX capacity hitting its stride, displacing northern white

Source: Internal Estimates, Infill Thinking

0

5

10

15

20

25

30

35

40

45

50

Aug-17 Oct-17 Dec-17 Feb-18 Apr-18 Jun-18 Aug-18 Oct-18 Dec-18

Mill

ion

s o

f Ton

s

Permian 2019 100 Mesh Demand

Total Permian 2019 Demand

Worst case scenario displacement from

the Permian Basin around 25 million tons*Assumes 100mesh becomes 75% of total demand

Capacity buildout timeline

Early producers are had significant quality and delivery issues but are

now hitting their stride. Coupled with slower demand due to infrastructure

constraints these factors are placing significant stress on northern white.

10/1/2018 • 10

Technical need for northern white remains

0.0

0.5

1.0

1.5

2.0

2.5

3 4 5 6 7 8 9 10 11 12 13

Mill

ion

s o

f Ton

s

K Psi

Reported Pressures of Permian Basin Wells

69% of Proppant6% of Proppant 23% of Proppant

*Completions January 2016 through December 2017

Resin

Northern White 40/70 & 100 Mesh

West Texas 100 Mesh

West Texas 40/70

3% of Proppant

A technical need will remain for northern white 40/70 and 100 Mesh

giving an advantage to companies with a full suite of product offerings

MidlandDelaware

Source: Energent Group

10/1/2018 • 11

73.1 million tons of in-basin capacity coming online

Company Play Tons Operational

Atlas Permian 3.0 Q2 2018

Black Mountain Permian 6.0 Q2 2018

Emerge (Superior) Eagle Ford 2.4 Q2 2018

South Texas Frac Eagle Ford 1.0 Q2 2018

JW Sands Eagle Ford 1.5 Q2 2018

Total Greenfield Capacity 13.9 million tons


Badger Permian 3.0 Q3 2018

Covia Permian 3.0 Q3 2018

Covia Permian 3.0 Q3 2018

Capital Permian 2.8 Q3 2018

US Silica Permian 2.6 Q3 2018

West TX Sand Co Permian 3.0 Q3 2018

Wisconsin Proppants Permian 3.0 Q3 2018

Monarch Eagle Ford 4.0 Q3 2018



Atlas Permian 3.0 Q4 2018

Ultra Fine Silica Eagle Ford 4.0 Q4 2018

Covia MidCon 4.0 Q4 2018

Preferred MidCon 3.0 Q4 2018



Aequor Permian 3.0 Q4 2017

Alpine Permian 3.0 Q4 2017

Black Mountain Permian 5.0 Q1 2018

High Roller Permian 3.5 Q1 2018

Preferred Permian 3.3 Q1 2018

VIsta Permian 3.0 Q1 2018


Softening demand in Q3 and Q4 against multiple new capacity

additions indicate pricing will be challenged on multiple fronts

Source: Internal Estimates, Company specific websites

10/1/2018 • 12

Colorado dune sands unfit for usage in the DJ

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

3 4 5 6 7 8 9 10 11 12 13

Mill

ion

s o

f Ton

s

K Psi

Reported Pressures of Denver-Julesburg (DJ) Basin Wells

95% of Proppant


Resin


Local 100 Mesh

Local 40/70

5% of Proppant

Colorado dune sands are not recommended for usage in hydraulic

fracturing due to very low silica content in the sands which provide low

crush resistance and high acid solubility

DJ Basin


Resin


Local 100 Mesh

Local 40/70

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

3 4 5 6 7 8 9 10 11 12 13

Mill

ion

s o

f Ton

s

K Psi

Reported Pressure of Eagle Ford Wells

10/1/2018 • 13

Requirements in the Eagle Ford are higher than most plays

15 Million Tons

68% of Proppant

5 Million Tons

24% of Proppant

2 Million Tons

8% of Proppant

Eagle Ford wells begin at 7k with any density. Most operators in the

basin range between 7k and 10k for most of their work



0

50,000

100,000

150,000

200,000

250,000

300,000

3 4 5 6 7 8 9 10 11 12 13 14 15

K Psi*Completions January 2016 through December 2017

*Assumes a 0.65 pressure gradient

Proppant pumped by reported well pressure

10/1/2018 • 14

MidCon local sands are viable for much of the demand profile

Resin


In Basin 40/70

In Basin 100 Mesh

8.3 Million Tons

99% of Proppant

2.8 Million Tons

37% of Proppant

8.4 Million Tons

100% of Proppant

6.8 Million Tons

83% of Proppant

STACKSCOOP

10/1/2018 • 15

Direct sourcing is awaiting a full last mile solution


Top 100 proppant consuming E&Ps in 2017

2 million

tons +

1 million

tons +500,000

tons +

Actively self-sourcing, or seeking RFPs

Not currently self-sourcing

EOGOxy

Pioneer

Encana

Extraction Devon

100,000

tons +

Chesapeake

Anadarko

Concho

Sanchez

Marathon

Continental XTO

Newfield

Conoco

Vertically integrated (own their own sand mine)

HessCNX

SWN

Ascent

Encana

48%Of total 2017

demand

represented by

E&Ps either actively

self sourcing or

requesting RFPs

90%Of proppant

consumed by the

top 100 E&Ps

Full adoption of E&P self

sourcing if dependent on

effective last mile solutions

It’s all about frac crews

Rig Count decoupled from frac sand demand

Market projected to be 100 million tons this year

Nearly doubling the boom of 55 million tons back in 2014

Headwinds are forming due to lack of pipeline infrastructure, capping market growth

Well designs still moving toward more intense finer grade designs across the industry

The desire of some E&Ps to directly source proppant is changing in many cases how it is sold and delivered to the well site

True last mile solutions will be integral to success with this emerging customer requirement

Growth of greenfield in-basin capacity

Numerous challenges both structural and technical exist and will need to be solved to be successful

Labor and trucking shortages will provide challenges specifically in the Permian Basin

10/1/2018 • 16

Final thoughts on the market

Source: Covia

Proppant ComparisonFIT FOR PURPOSE VS. NORTHERN WHITE

Proppant quality matters for production of hydrocarbons

If you are holding wells for production beyond initial IP, quality northern white proppants should be considered over other Tier II proppants

Conductivity testing shows a significant degradation in performance of West Texas100 mesh material

Degradation is due to fines generation and migration

Northern White Sand generated 11% fewer fines than regional sand

Crushed sand = increased turbulent flow due to increased angularity of the crushed sand, degradation of proppant pack, insufficient flow path to reservoir

Northern White 40/70 testing indicated increased performance of wells.

Due to increased flow paths from higher roundness and sphericity allowing for better production

Sub-angular substrate allows for inferior long-term production.

A 2x increase in turbidity between Northern White and West Texas material equates to performance differences as well as operational challenges from a “dirtier” material

Real world performance indicates 16% greater production from Northern White compared to Texas Gold material due to turbidity andother performance issues

Up-front Savings from in-basin sands are evaporated within 6 months of production at $60/bbl realized

After 24 months, Northern White wells generated $1 million more in oil production than comparable wells completed with Texas Gold material

Conditions in the Eagle Ford are more harsh than the technical capabilities of either Texas Gold or in-basin sands

10/1/2018 • 18

Findings indicate advantages to using Northern White material

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

50 70 80 100 120 140 200 pan

10/1/2018 • 19

100 Mesh testing indicates a distinct performance advantage100 Mesh 6k Continuous Hold Conductivity Testing

Conductivity,

mD

-ft

Day

50

100

150

200

250

300

350

0 2 4 6 8 10 12 14

Greater Northern White

conductivity after two

weeks of testing

1.7x

15% fines generation after

just two weeks. What

happens after two years?

Northern WhiteWest Texas

Particle size distribution before and after testing

Perc

ent R

eta

ined

West Texas material after 2 Weeks:

A 15% fines generation increase caused

57% decline in conductivity performance.

Sand Type Crush Strength (psi)

White Sand 11-12k

Texas Gold 7-8k

WTX Regional 9-10k

Source: Covia

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

50 70 80 100 120 140 200 pan

10/1/2018 • 20

100 Mesh testing indicates a distinct performance advantageNormalized 6k hold conductivity results

Conductivity,

mD

-ft

Day

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 2 4 6 8 10 12 14

Reduction in initial

conductivity seen in

West Texas Sands

60%

15% fines generation after

just two weeks. What

happens after two years?



Perc

ent R

eta

ined

West Texas material after 2 Weeks:

A 15% fines generation increase caused

57% decline in conductivity performance.

Sand Type Crush Strength (psi)

White Sand 11-12k

Texas Gold 7-8k

WTX Regional 9-10k

Source: Covia



Norther White Sands

16%vs.

10/1/2018 • 21

Quality effects productivity, quality sand will produce longer

Northern White Before Testing Northern White After Testing

WTX Field Sample Before Testing WTX Field Sample After Testing

6k psi for two weeks

6k psi for two weeks

100 mesh Fines generation on from the West Texas sand sample chokes out

production after an extended period under pressure due to inferior strength

Source: Covia

10/1/2018 • 22

40/70 shows consistent, pronounced conductivity differences40/70 Mesh 6k Continuous Hold Conductivity Testing

Conductivity,

mD

-ft

Day

250

300

350

400

450

500

550

600

650

700

0 2 4 6 8 10 12 14

average performance

difference of northern

white over West Texas

67%



Perc

ent R

eta

ined

Similar particle size distributions between

sand types before and after testing still

yielded an advantage to Northern White due

to more ideal roundness and sphericity

Northern White

West Texas

Sand Type Sphericity Roundness

White Sand 0.8 0.8

Texas Gold >0.6 >0.6

WTX Regional >0.6 >0.6

Source: Covia

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

30 40 45 50 60 70 100 Pan

10/1/2018 • 23

40/70 shows consistent, pronounced conductivity differences

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

30 40 45 50 60 70 100 Pan

40/70 Mesh 6k Continuous Hold Conductivity Testing

Conductivity,

mD

-ft

Day

50%

55%

60%

65%

70%

75%

80%

85%

90%

95%

100%

0 2 4 6 8 10 12 14



Perc

ent R

eta

ined

Similar particle size distributions between

sand types before and after testing still

yielded an advantage to Northern White due

to more ideal roundness and sphericity

Sand Type Sphericity Roundness

White Sand 0.8 0.8

Texas Gold >0.6 >0.6

WTX Regional >0.6 >0.6

Source: Covia



West Texas Sands

31%Reduction in initial


Norther White Sands

14%vs.

10/1/2018 • 24

Performance differences also stem from turbidity of product

Sand Type Turbidity (FTU) Acid Solubility

White Sand <50 <0.6%

Texas Gold <75 <2.0%

WTX Regional 100 <3.0%

Northern White sands are generally “cleaner” with less silt or clay material attached to each

grain. These impurities cause break free down hole where the clays swell and choke off

production.

Northern White Range West Texas Range

Silt and clay stuck

to sand grains

Northern White

West Texas

Impurities dissolve in acid

meaning that to place 7,500

tons of proppant, 7,735 tons

must be pumped or an

additional 235 tons of

material must be purchased.

Source: Covia

10/1/2018 • 25

Real world performance impacted by proppant quality

-

0.50

1.00

1.50

2.00

-

0.50

1.00

1.50

2.00

-

0.50

1.00

1.50

2.00

-

5.00

10.00

15.00

20.00

25.00

30.00

-

5.00

10.00

15.00

20.00

25.00

30.00

-

5.00

10.00

15.00

20.00

25.00

30.00

Northern White

Texas Gold

Mixed

Significantly more interventions

required across multiple wells

Northern white wells peak longer

providing uplift

Brown sand wells peak at the

same level but fall off quicker

Majority of wells are in the

outperform range

Most wells are in the

underperform range

Virtually all wells are in the

underperform range

Barr

els

per

late

ral fo

ot P

roduction

Barr

els

per

late

ral fo

ot P

roduction

Using Texas Gold as a proxy for in-basin sands, observations in well performance indicate wells

completed with higher quality proppants generally outperform their peers due to the proppant

pack's ability to keep fractures open while maintaining conductivity.

Outperform

Underperform

Outperform

Underperform

Outperform

Underperform


10/1/2018 • 26

Well averages showcase performance differences

-

0.20

0.40

0.60

0.80

1.00

1.20

1.40

-

2

4

6

8

10

12

14

16

18

20

Characteristic effects seen in well

cohort averages

Barr

els

per

late

ral fo

ot P

roduction

Barr

els

per

late

ral fo

ot P

roduction

16%

21%

When performance is averaged, characteristic decline curves indicative of the quality

of proppant used become clear. Northern white wells peak at the same level but

maintain higher production longer due to better sand performance

IP is an ineffective comparison

as wells peak at similar levels

Northern white

production advantage

over brown sands

16%

Northern White

Texas Gold

Mixed


10/1/2018 • 27

Up-front savings of cheaper proppant quickly wiped out

Production Month Northern White Texas Brown Mixed

Month 1 $320,716 $173,595 $357,064

Month 3 $1,403,706 $1,079,851 $1,407,310

Month 6 $2,898,257 $2,219,514 $2,423,634

Month 12 $4,674,795 $3,829,757 $3,524,935

Month 18 $6,046,384 $5,017,743 $4,375,911

Month 24 $7,051,444 $6,012,815 $5,027,012

Northern White After 6k Testing

Brown Sand Sample After 6k Testing

Assuming a savings of $50/ton on 7,500 tons, the up-front

advantage from cheaper locally available sands wiped out

within three months of production

Assumes normalized production from a 7,500 foot well and $60 WTI realized

$1M difference

in production

Up-front

savings lost


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