Completion & Stimulation Unconventional Reservoirs ITBA

Completion & Stimulation

Unconventional Reservoirs

ITBA

J. Ponce

Oct 2014

2

Completion & Stimulation Unconventional Reservoirs

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Argentina’s Reality

Source: CAMMESA

Argentina’s Natural Gas Production & Consumption

Argentina is highly dependent on fossil fuels!

Decreasing oil production Need to import

Gas demand is not satisfied with

local production Need to import at high prices

2/3 of electricity generation

based on fossil fuels

From fossil fuels

From other

sources

4


Unconventional Reservoirs Some ways of defining UR: trivial definition: those that are not conventional!

Based on permeability

– Those with permeability to gas less than 0.1 mD

Based on fluid properties (mainly viscosity)

– Those with extremely high viscosities even with large permeability

Based on where the hydrocarbons were generated and migration if any

Based on fluid flow within the reservoir

Based on productivity and economics

– Need of stimulation (mainly hydraulic fracturing) to get commercial rates

Categories

Tight sandstones

Organic rich shale reservoirs

CBM

Hydrates

Oil shale ≠ Shale oil, tar sands, and extra heavy oil sandstones Source: Wood Mckenzie

5

Hydrocarbons are generated, trapped and stored in the same rock

Negligible migration or if any within the reservoir

Definition of word “shale” based on grain size rather than mineralogy composition (rock type)

Shale gas, shale oil. Barnett, Eagleford, Vaca Muerta, Lower Molles

Grains size < 1/256 mm

Low porosity (< 12%) and extremely low permeability. Kv ≈ +/- 0.01 Kh

Fluids go from dry gas to oil

Interest on high API oil as it will be the only one with capacity to flow. High pressure

Rocks go from siltstones to carbonates with variable clay content

Focus on high quartz content, then carbonates. We prefer clays < 30 %

High lamination = issues for frac propagation

Darcy’s flow is the exception rather than the rule

Storage in poral volume, natural fissures, dissolved and adsorbed


Organic Rich Shale Reservoirs

6

Hydrocarbons are generated at source rock

Migration to other reservoirs where they are trapped and stored

Seals are true shales or extremely low permeability rocks

Definition of word “tight” based on low permeability

Tight gas, tight oil. Cadomin, Lance, Quintuco, Lajas, Precuyo, Basement

Low porosity (< 15%) and low permeability. Kv ≈ +/- 0.1 Kh

For taxing purposes definition of less than 0.1 mD


Pressure is important but sub-pressured reservoirs are still possible to be produced

Rocks go from siltstones to carbonates including volcanic rocks as well

Rocks are in general cemented with variable clay content

Darcy’s flow is the dominant mechanism

Storage in matrix porous volume, natural fissures and dissolved


Tight Reservoirs

7

Hydrocarbons are generated at source rock

Migration to other close tight reservoirs where they are trapped and stored

Seals are source rocks

Sandwich or Oreo cookie concept

Production mainly from tight rock but feeding from source rock as well

Arbitrary definition

Tight gas, tight oil. Bakken, Upper Molles


Pressure is important

Rocks

Stacked reservoirs

Flowing mechanism is a combination dominated by Darcy’s flow

Storage in matrix porous volume, natural fissures, dissolved and adsorbed


Mixed Reservoirs

8

Three sources

Free gas. Only small molecules can fit extremely small pores (methane, ethane)

– Gas in matrix. Inorganic and organic pores

– Gas in micro and nano fissures

Sorbed gas. Need enough drawdown to be produced

– Within kerogen pores

– On non swellable clays

Dissolved gas

– In water

– In non mobile oil


Hydrocarbon Storage in Shale Gas

Source: Li, 2011

Source: Williams, 2012

Source: Loucks, 2009

9

Storage in void space which include pores and fissures

Larger molecules = bigger pore space

Production of oil, gas and water in some cases

Even if bigger molecules are present they can not move!

In pure matrix only small molecules can flow (reason for high API)

In micro and macro fissures it is easy to flow but volume is limited

Effect of depletion

Gas is dissolved in oil and water


Hydrocarbon Storage in Tight Oil

Source: Bustin, 2009 Source: Zoback, 2011

Source: Jarvie, 2008

Source: Pitman, 2011

10

Within the matrix gas and/or oil travel extremely small distances

Hydrocarbons move to nano, micro and macro fissures

All fissures conform the natural network

Some of them were healed and activated while fracturing

Natural fissures network intersected and potentially activated by hydraulic fracture provides their flow to it

Multiphase flow during early period


Flow Mechanism in Shales

Source: Tella,

2011

Source: Pollastro, 2007

11

Oreo cookie model.

Sweet production from reservoir in between, in general a tight one

Source rock provides additional flow or recharges reservoir

Extremely slow process but still useful

Tight reservoir

Flow thru pore space in the matrix and natural fissures

Both feeds hydraulic fracture


Flow Mechanism in Mixed / Tight Reservoir

Source: Sterling, 2012 Source: Wilson, 2012

12


Unconventional Reservoir Continuum

Source: CSUR, 2012

13


Hydrocarbons Types

Fluid type is driven by kerogen type and level of maturity

Under saturated (black or dead oil)

Saturated

Volatile oil

Gas condensate

Wet gas

Important properties

GOR: function of Ro (maturity)

Viscosity: directly linked to GOR & T, therefore a function of maturity as well

Volume factor

Maturity is governed by temperature. Burial history and exhumation

Exhumation can move fluids to two phase envelope which is not preferable

Stable phase behavior favored by high T & P

14


Fluid Behavior in Nano-pores

Due to similar dimensions of pore sizes and hydrocarbons molecules there are high rock / fluid interactions

Appreciable van del Waals’s forces

Important surface forces (wettability, adsorption)

Interfacial tension is altered (high capillary pressure)

Complex flow (Darcy’s flow is not the only mechanism!)

Slow moving pressure transients at reservoir level but it could be different at wellbore if drawdown is important (flowing pressure below bubble pressure)

SPE 158042

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Fluid Behavior in Nano-pores

Standard PVT analysis is no longer valid

What we produce at surface it is not what we have at reservoir conditions

Below 100 nm (pore size) effects start deviating appreciably

Deviations from measured PVT data become greater as pore size decreases

Two-phase envelope shrinks and fluid starts to behave more like a dry gas

Condensate viscosity decreases under confinement. Increase in liquid production

Liquid dropout is reduced as pores are smaller

SPE 160099 SPE 169493

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No commercial rates below 0.1 mD unless well is hydraulically fractured

Shale permeability << tight permeability so situation even worse

If oil or multiphase flow are present rates are much lower


Productivity

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Productivity and Reservoir Contact Area

Open hole completion: ~7.2 m2 of contact

Cased hole completion: ~0.8 m2 of contact

Fractured completion: ~6,000 m2 of contact

Hydraulic fracture increases reservoir contact in a vertical well at least 3 orders of magnitude!

Open hole completion (50 m): ~35.9 m2 of contact

Open hole completion (1000 m): ~718.2 m2 of contact

Cased hole completion: ~8.4 m2 of contact

Fractured completion: ~66,000 m2 of contact

Multi-hydraulic fractured horizontal well increases reservoir contact over a vertical one ~5 orders of magnitude!

11 fracs stages

This is the main reason to justify multi-fractured horizontal wells!

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Multi-fractured horizontal wells provide highest productivity index

No other combination is better

Large number of fracs provides higher IPs but incremental production decreases with the number of stages

Reservoir deliverability after fracture vs economic trade-off

Transverse hydraulic fractures are only attractive at low permeability

Below ~0.5 mD, it is the best option. Choke flow is negligible


Multi-fractured Horizontal Wells - Reasons

Source: SPE 102616

Source: Wang, 2009

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Any Other Reasons? Mandatory state regulations

Minimum ground disturbance

Access to reservoirs under populated areas, farming extensions, preserved lands,

water resources that can not be reach vertically

Environmental and cost-effective solution to replace multiple vertical wells

without impacting large surface areas Closer well spacing to cover limited drainage areas requires more wells

Pad drilling and completion. Offshore approach

Production facilities in the same place of wells. Smaller foot print

Still limited number of vertical wells Discovery, appraisal wells. They can be used for monitoring purposes later

Pilot holes

Disposal wells

Source: Bentek Energy, 2013

Source: epmag.com Source: CSUR, 2010

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Well planning

Spacing

Lateral length, orientation, landing zone

Depletion plan

Drilling / Geosteering

Geologic discontinuities

Well profile

Completion

Technique

Stages

Frac design

Environmental issues

Water

Ground disturbance


Well Design Considerations

Source: Hess

Begin with the hydraulic

fracture in mind!

21


Development Plan

22


Well Construction – Factory Mode

23


Potential Leaking Pathways

Source: EPA, 2012

24


Wellbore Integrity – Protective Layers Conductor casing

Cement to surface between conductor casing and surface

ground

Surface casing below deepest freshwater aquifer

Hydraulic pressure test. LOT, FIT

Cement to surface sealing surface casing in place

Intermediate casing

Cement to seal intermediate casing in place Cement bond logs

Production casing

Cement isolating productive interval Cement bond logs

Salinity of produced water

Production string (tubing) Watertight pressure test

Production PKR Annulus pressure monitoring during

well life

Double barrier X-mas tree assembly Source: CSUR, 2012

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In vertical wells there are no major issues for fracture initiation

Unless high deviation exits, hydraulic fracture is fully connected to wellbore

As hydraulic fracture orientation is dictated by geomechanics, wellbore axis must be defined with fracture orientation in mind

Hydraulic fracture grows in the same plane of the two maximum principal stresses

To get transverse fractures well must be oriented accordingly

No impact on productivity if permeability is lower than 0.1 mD. In addition, it is difficult to get full connectivity with wellbore

Hydraulic fractures at any other angle are difficult to initiate. Tortuosity. Screen-outs


Well Orientation

Source: Halliburton Source: Halliburton

26

By reservoir type

Multiple stacked layers: multi-fractured vertical wells

Single or double reservoirs: multi-fractured horizontal wells. Vertical wells to gather information

By completion type

Cased and un-cemented completions. Packers to isolate intervals

Cased and cemented completions


Completion Tight Reservoirs

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By reservoir type

Single reservoir: multi-fractured horizontal wells. Few verticals to gather information

Double reservoirs: dual multi-fractured horizontal wells. Expensive!

Completion type

Un-cemented cased completions. Packers to isolate intervals or just liners

Cased and cemented completions


Completion Shale Reservoirs

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Big debate around this issue. Let’s separate commercialism from engineering!

If natural fissures are a proven mechanism of well productivity, it makes sense to use open hole completions

Cement might damage fissures if the are open at the time of cementing

In general completion operations take less time

If case of wellbore stability issues, cased and cemented completions

If a fault that brings water is encountered it is possible to isolate that interval

First wells should be completed with cemented completions


Open Hole vs Cemented Completions

29

Open hole completions

Bare foot

– Lowest cost

– Simple

– No cement = no damage but no isolation

– No diversion

Slotted liner

– Low cost

– Simple

– No cement as previous method

– Poor diversion

Mechanically staged process

– Affordable cost

– No cement as previous methods

– Diversion is ensured

– Operationally simple but…


History of Completion Techniques

30

Cased hole completions

Plug & Perf

– Excellent stage isolation

– Extensive track record

– Cement to isolate

– Possibility to perform individual stage diagnostics

– Need to drill out plugs

Mechanically staged process

– In essence similar to open hole system but with cement to enhance isolation

CT based

– Thru CT or thru annulus options

– Good isolation between stages if mechanical means are used (sand plugs have low efficiency)

– Reduction of completion time

– Limitations of CT

– If CT gets stuck, it could be a nightmare

External casing perforating

– A patented system that industry did not accepted as a consequence of limitations of patent

– Method proved useful but was relegated later


History of Completion Technique

31


Bare Foot Completion

32


Slotted Liner Completion

33


Mechanically Staged Completion

34

Cased and cemented

Cased and un-cemented


Completion Techniques

BOT

70-75 % of current wellbores are

completed using P&P technique

20-25 % are cased and

uncemented completions

Combination of both methods

has been introduced and are

under utilization but with limited

applications

5 % or less are performed using

techniques conveyed on CT

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First stage

TCP perforating conveyed on CT

Abrasive jet perforating conveyed on CT or jointed pipe

Casing gun perforating conveyed on wireline tractor

Casing toe gun

Hydraulic valve

Toe valve

Wet shoe

Rupture disk

Subsequent stages

Wireline conveyed casing gun perforating

TCP perforating conveyed on CT

Abrasive jet perforating conveyed on CT or jointed pipe

Casing gun perforating conveyed on wireline tractor


Cased and Cemented

36

First stage

Hydraulic valve

Toe valve

Rupture disk

TCP perforating conveyed on CT or jointed pipe (contingency)

Abrasive jet perforating conveyed on CT (contingency)

Casing gun perforating conveyed on wireline tractor (contingency)

Subsequent stages

Single or multiple array of farc sleeves / ports

TCP perforating conveyed on CT (back up plan after DO ball seats)

Abrasive jet perforating (back up plan after DO ball seats)

TCP perforating conveyed on wireline tractor (back up plan after DO ball seats)

Wireline conveyed casing gun perforating (back up plan after DO ball seats)


Cased and Un-cemented

37


Pro’s and Con’s – Quick Review Fix devices run as part of completion string (e.g. frac ports)

Need to have really good understanding or reservoir quality to define landing depth of every frac port in front of sweet spots

Short time for analyses as completion is run as part of the production string. It requires dedicated, efficient and well integrated teams

Frac behavior must not be an issue, likelihood of screening out is remote. Development phase

Not recommended for exploration, appraisal stage

Excellent balance between cost and completion cycle time

It requires very good communication between operational crews from different service providers on location to avoid serious mistakes

When open hole completion is used and natural fissures provide some production they must be considered seriously

Isolation between stages can be questionable under certain conditions

Wellbore stability is a key issue when deciding to use this technology

38


Pro’s and Con’s – Quick Review Pin point stimulation

Fracs are directly targeted where the teams want to

Time for reservoir related analyses is not an issue

From completion cycle time perspective is much more less effective than frac ports systems. (average: 3 to 7 stages in one day)

Highly recommended for exploratory and appraisal wells

If sanding out happens it is easy to clean out the excess of proppant and continue with the program

Versatility to change decisions as we always have the control on where to put the perfs

These are cased and cemented completions so we need to rely on cement isolation (an issue in horizontal wells)

If any production is coming from natural fissures we are not capturing it

Easy for operational crews on location to understand the methodology

39

Most applied technique for now

Simple in the essence plugs and casing guns are used to connect reservoir to wellbore and to isolate intervals

Plug + setting tool + CCL + casing guns + firing head + cable head in a single BHA

Plugs

– Composite materials

– Blind

– Flow thru or frac plugs. Balls to isolate flow of fluids. Balls can be degradable

Casing guns

– Single or multiple guns in single run that can be fired selectively


Plug & Perf

Source: Halliburton

Source: Schlumberger Source: Halliburton

40

Composite plugs have different pressure and temperature ratings

Isolation is ensured for a certain period. After that material start degrading

What do I have to take a look at to avoid choosing unsuitable models?


Pressure Test of Plugs

Source: Baker

41

Degradable balls

No need to drill out plugs to produce the well. Possible to install plugs beyond CT capabilities

CT only required if ball seats need to be drilled out to run tools (e.g. PLT)

Electrolytic reaction degrades material (nano components)

Most likely in the future we will see disintegrating seats


New Ball Technology

Source: Baker

42

Plug & Perf technique implies pumping down casing guns and plugs

To increase efficiency both are pumped together in a single run

A clean wellbore is critical

Sand or debris can cause downhole tools to get stuck

Previous frac stage must be flushed properly

Flush surface equipment (mainly well control devices) to ensure no proppant remains inside that prevent them to work properly

Weight control is crucial during entire operation

Weight check in vertical section. Tension in the horizontal section should be close to this value. Ensure to check weight at the same rate you pump in the horizontal

Pump down rate depends on casing size

At least 10 bpm are required to push the plugs but 15 to 20 bpm are typical

Pump at 2 bpm while perforating to ensure cable is in tension and to prevent stuck

Communication is paramount between wireline and pump trucks


Pump Down Operations

43

A step change compared to conventional systems

Old systems could only fired a certain number of guns, normally 3. Based on polarity

Guns could only be fired in a determined sequence

If one fails, need to take out remaining ones as live guns

Safety issues with certain firing devices

New design allows firing multiple guns

Sequence is defined by the user. Up to 40 addresses

Unlimited number of casing guns limited by lubricator length

High flexibility (new switch technology)

If one fails we can continue with other guns

High intrinsic safety

Completion & Stimulation Unconventional Reservois

Selective Perforating Guns

44

Just a fancy name for limited entry perforating. Limited = inefficient

Main objective: reduce pumping costs

Based on choked flow. High pressure drop at perfs. At least 500 psi but no more than 1500 psi. Reduced number of holes. Not all holes are open!

Dynamic problem. Simple at first glance but complex if we want to tackle it seriously

Once first proppant starts passing thru perforations, this condition is lost

Not all clusters take fluid and of course not all will ever produce!

Confirmation with PLT. As a rule of thumb 1 out of 4 does not produces back

Increasing the number of clusters reduces efficiency affecting production inflow


Cluster Perforating

source: SPE 144326

45

Well integrity is a must in everyday operations

In UR it is usual to work with HP (>10 kpsi) at surface

Special equipment, barriers and procedures


Well Control Issues

Source: NOV Elmar Source: Schlumberger

46

Assume there is a gas well which was shut in after fracturing and WHSIP= 6000 psi. We need to run the next plug + the selective casing guns. How much weight do we need in our WL string to overcome that pressure? Consider a 0.33” cable and you have on location steel and tungsten weight bars/stems? Lubricator length is 20 m. Plug + BHA weight is 300 lb and measures 10 m. Pack-off friction is about 100 lb

What is the reasoning behind having steel and tungsten bars?

Is anything missing?


Well Control Operations

47

Horizontal well length: 500 to 3000 m

Usually longer laterals are better but CT capabilities and other issues limit length

Distance between frac stages: 1 to 1.5x frac height

Spacing between clusters: 10 to 20 m

Length of perf cluster: 4 x well diameter

Number of stages: depending on lateral length up to 60

Limited in certain cases by completion technology

Number of clusters: 3 to 10. Keep in mind efficiency to define clusters


General Horizontal Well Architecture

48

What is the maximum hole angle that can be logged with wireline or slickline?

Gravity is our friend in the vertical section and partially in the deviated section


Wireline Operations

∆𝑇 = 𝑊 cos ∅ − 𝜇𝑊 sin ∅

Friction plays an important role. It can not be eliminated completely

Additives

Tool shale

𝜇= 0.3

∅= 73º

𝜇= 0.2

∅= 78º

𝜇= 0.4

∅= 68º

49


Mechanically Staged Completions

1/8in & 1/16in

increments in ball size

50

One type to initiate the process

Hydraulically or CT activated

Remaining sleeves ball operated

Old models just one sleeve per ball size

New models can open 4 to 6 sleeves with a single ball miming clusters

Multiple vendors with variations

Evaluate well!

If they do not work it can be painful


Frac Ports or Sleeves

source: Halliburton

source: Weatherford

51

Swell time is in general a limiting factor

There is no enough time between completion string running and stimulation

Swell time dependent on several factors

Fluid temperature

Rubber thickness

OD and ID difference of packer and wellbore

Packer length

For oil swell, oil composition is controlling factor

For water swell, water salinity is controlling factor

Best suited for zones where caliper is not good

It exerts less stress on formation

If frac fluid cools down swelling element there is potential of shrinking


Swellable Packers

52

Nine Sleeve Example (4.5” Casing)

Stage #1: 4 sleeves per stage – 2.625” OD activation ball










i-Frac System

A single ball in each frac stage

opens four port sleeves that serve

as “perf” clusters – without the

need for perforating.

53


Example of Actual Well Using Frac Sleeves

54

The best of both worlds!


Hybrid Design

55

Plug and Perf

2 hr delay between fracs

“unlimited” # stages

Perf clusters possible

Full bore ID

Cement isolation between fracs

Cement can damage natural fractures

Procedure well known

Casing landing depths not critical

Less expensive but slower

Estimated utilization

– 100 % shale gas wells

– ~70 % shale oil wells


Techniques Comparison Summary Open Hole w/ Sleeves

Continuous frac ops

Limited # stages?

Cleanout is difficult

No cement

Intervention reduced

Downtime reduced

Completion string set points critical

Extra equipment required to joint “shows”

Quicker but more expensive

Estimated utilization

– ~30 % shale oil wells

56

Basically two approaches

Frac treatment pumped down CT

– Limited rate and frac volumes. Pin-point stimulation

Frac treatment pumped thru annulus between casing and CT

– Some volume is also pumped down CT to enhance application

Communication with reservoir

Abrasive jet perforating

– Sand plugs or mechanical plugs

CT activated frac sleeves

– Shifting tools


CT Based Frac Technologies

Source: Halliburton

57

Another application of the Bernoulli's equation

Pumping an abrasive laden fluid thru a small orifice (jet / nozzle) at certain rate creates a jet with enough momentum to cut holes thru casing, cement and reservoir rock

– Momentum transference is relatively inefficient. Cutting / spalling only occurs when force from fluid impingement is at least 1.5 times the compressive strength of the rock

– Stress on rock is proportional to V2

– Velocity is proportional to ΔP1/2

Larger ΔP promotes higher velocities but there are limitations in equipment. At least 2000 psi of ΔP is required

Synergy of pumping thru annulus simultaneously will not be covered in this presentation


Abrasive Jet Perforating

58

Perforations

Longer tunnels

Hole entrance less than 0.5 in

Burr on hole entrance

Stress cage along perf tunnel

Higher breakdown pressure


Perforations vs Cut Holes Cut holes

Limited hole length (max 10 in)

Big entrance hole (> 0.8 in)

Smooth hole entrance

No stress cage

Reduced near wellbore friction

Temperature effects on explosives is not an issue

Hardesty, 2012

SPE 83950

59

Multi-fractured HZ wells

Options to cut holes at 60°, 120° or 180° (oriented holes)

– Consider stress regime to account for fracture initiation (top-down or side by side) to define jets orientation


Abrasive Jet Perforating Application

TTS

TTS

60


Zone Select

source: Weatherford

61


Zone Select – Cont’d

source: Weatherford

62

Axial forces

Buoyed weight of the CT

Friction drag (in the stripper and against the wellbore)

Set down weight, WOB, or overpull

Pressure x area (where the CT passes through the stripper)

Tension from the CT reel

Hydraulic drag due to fluid flow

Normal forces

Buoyed weight

Curvature

Buckling


Torque & Drag – CT

63

Consider a long deviated well with an 2,000 m lateral (90deg) and a TVD depth of 3,000 m. We are attempting to cleanout the well with a 2” CT – 3.072 #/ft string (workover fluid of 8.5 ppg, µ=0.3). Ignore any dogleg effects

Determine:

– A) Hook load when rotating on bottom

– B) Hook load when RIH

– C) Hook load when POOH


Torque & Drag Calculations - CT

∆𝑇 = 𝑊 cos ∅ − 𝜇𝑊 sin ∅ 𝐹𝑓𝑟𝑖𝑐 = 𝜇N = 𝜇W sin(dev)

Buoyed weight = (65.5 – fluid density)/65.5 * pipe weight

BW = 2.673 ppg

A) HL = 2000 * 2.673 / 0.3048 + 3000 * 2.673 / 0.3048 * cos(90º)

B) HL = HL(A) – 0.3 * 2.673 * 3000 / 0.3048 * sin(90º)

C) HL = HL(A) + 0.3 * 2.673 * 3000 / 0.3048 * sin(90º)

64

In unconventional reservoirs it is critical to create a large stimualted volume in order to contact huge reservoir area

Ability to create such a large SRV is a combination of geological factors and hydraulic fracture design as well

Difference in magnitudes between both principal horizontal stresses

Presence, density and orientation of natural fissures and/or planes of weakness

Fluid pumped (X-linked vs slickwater)

Frac pumping rate


Stimulated Reservoir Volume (SRV)

65


Geomechanics Stress regime impact

Frac azimuth

Frac initiation

Complexity

Frac initiation

Normal (Sv > SH): top – down

Strike-slip (SH > Sv): both sides

Frac propagation

Strike-slip: turning and twisting (choke effects). Proppant transport

Thrust or strip-slip & bedding: no reorientation = pancake fractures

Vaca Muerta

High compressional effects close to the Andean foothills

Normal, strike-slip and thrust are common. Need to understand local stress regime

Rahman, 2002

66


Key Factors Impact on Frac Complexity Geo factors (limited control = where

we land the well or where we frac )

Stress anisotropy: best if SH – Sh < 5 %

Natural fissures (density) / rock fabrics

Mean stress magnitude & direction

Frac design factors (manageable)

Wellbore orientation

Rate

Viscosity

67


Mineralogy and Rock Quality Rock quality (function of mineral composition)

Hydrocarbon storage, flow capacity

Fracability (easiness to frac)

Rock composition

Quartz

Carbonate / dolomite

Clays (if possible less than 30 %)

Organic content (kerogen & pyrobitumen)

Brittleness

Practical index, the higher the index the easier to open frac, to extend and to keep it open BI =

𝑄𝑡𝑧+𝐷𝑜𝑙

𝑄𝑡𝑧+𝐶𝑎𝑙+𝐷𝑜𝑙+𝐶𝑙𝑦+𝑇𝑂𝐶 BI =

(𝐸𝑏𝑟𝑖𝑡𝑡 +𝑣𝑏𝑟𝑖𝑡𝑡)

2 (E, 𝑣)𝑏𝑟𝑖𝑡𝑡 =

𝑋 −𝑋𝑚𝑖𝑛

𝑋𝑚𝑎𝑥 −𝑋𝑚𝑖𝑛

Too much carbonate: low TOC content, leaner rocks

Too much clay: very ductile, difficult to frac, poor production

VM

Mostly carbonates, with variable amounts of quartz and clays. In general clays content is low to medium. Certain zones have higher content of quartz with low carbonate and relatively low clay contents

EGI

68

Basically governed by three factors

Stress interference or shadowing

– Once the first fracture is created, pressure does not have enough time to dissipate causing an excess of stress on subsequent fractures. If both principal stresses are close to each other in magnitude, most likely there will be changes in orientation denoted by higher pressures and tortuosity. Additive effect


Number of Hydraulic Fracture and Spacing

Modified from: Waters, 2009

Source: Weijers, 2006

Min spacing between HF >

2 * Frac height

Source: Britt, 2011

69

Production interference

– As soon as individual hydraulic fractures start producing, pressure wave travels until it reaches the one from nearest hydraulic fracture. At this point it can be considered a virtual boundary was reached. Drainage volume increases until this point, thereafter it will drain at constant volume

Economics

– Larger number of hydraulic fractures will give higher IP but production interference will be reached sooner. At the same time completion cost will rise accordingly. Each company must define its strategy and optimums will depend on that


Number of Hydraulic Fracture and Spacing

70

Initiation requires axial forces and parallel stresses along wellbore axis

Existing conditions at natural fractures, packers, toe hole and surface csg rate hole

Avoidance of multiple fracture initiation

Waste of energy. Potential early screen-outs. Narrower fracture width

Perforate a short interval. Limited number of holes


Transverse Hydraulic Fracture Initiation

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Frac Initiation – Vertical & Horizontal Wells Frac barriers

Thick carbonate beds

Argillaceous beds

“A frac barrier is a zone which under given state of stress will prevent an induced fracture from propagating for a given pumping parameters (how much energy is provided)”

Bed interface can inhibit fracture propagation (decoupling)

T-fracs

Rock failure

Brittle layers: tensile

Ductile layers: shear

Natural fractures (horiz & vert): shear if properly distributed

More containment if injection point is at ductile layer

Ductile layers can affect fracture height and propagation path

Strike-slip regime impact on frac initiation: potential pancake fracs

UBA’s website

Gale, 2014

Where do we land the well?

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One well does not say the whole story

Need to plan and execute a dedicated field trial (pilot) where multiple wells are completed and variables can be managed in a way it is possible to discern what worked and what did not

Normally following parameters are explored

Spacing between well, landing zone, frac spacing, proppant and fluid amount, type of frac fluids and proppant , completion technique, perforation strategy, lateral length, number of fracs, choke management, etc


Field Trials

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Basically there are three types

Natural frac sand (NFS)

Ceramic (LDP, IDP, HDP).

Low density (different substrate: walnuts, plastic)

All can be covered with resin (RCPs)

Strength is enhanced. Fines are largely reduced

Special coating for tracing (NRT)


Proppant Tests

Source: Saint-Gobain

Source: Carboceramics

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After fracturing the well is put to flow, this initial period is called flowback

At the beginning mostly water is produced, then gas and oil start coming

In addition chunks of drilled out plugs, proppant, unbroken gel and other debris are brought to surface and it is required to clean out properly to avoid plugging up the well

Ensure equipment is rated for working pressure plus safety factor

In addition take into considerations rates, temperatures and type of fluids


Flowback and Solid Management

1. Choke manifold

2. Sand separator

3. Plug parts catcher

4. Test separator

5. Tank or pit

6. Flare

1

5

6

4

3 2

5

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Well Cost Economics of unconventional developments are highly driven by cost as

production is limited by low reservoir deliverability

Well capital expenditures from IHS CERA, 2011 Drilling: 40 %

Tubulars: 21 %

Consumables incl. bits: 21 %

Rigs: 21 %. Rig labor: 7 %

Cement: 9 %

Site preparation: 12 %

Others: 9 %

Completions: 50 % Wellhead, Xmas tree, packers: 15 %

Hydraulic fracturing materials: 38 %. Equipment & crews: 25 %

Related services: 5 %

Labor (well testing): 8 %

Other: 9 %

Facilities: 10 % Materials & equipment: 60 %

Construction: 25 %

Project management: 5 %

Other: 10 %

Source: energiaynegocios.com.ar, 2013

Source: platinumenergysolutions.com, 2013

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Well Cost for VM In general cost breakdown is similar to US (+/- 5–10 % difference per item)

Labor cost percentage is much higher

O&G goods & services are 2 – 3 times more expensive

Assuming similar productivity as analogous shales in US (mother nature provides

the reservoir so no possible to tell her what it has to deliver!)

Breakeven oil price in US at least

55-60 u$s/bbl

With current development costs,

breakeven price 2-3 times higher in

Argentina

At least should be 110-180 u$s/bbl

For gas breakeven price in US is

above 4 u$s/mcf

In Argentina should be 8-12u$s/mcf

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Thanks!

Cabot’s 10-well pad operations in Marcellus

Jorge E. Ponce – [email protected]

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Food for Thought

Insanity: “…doing the same thing over and over again

and expecting different results…”

Documents

Completion & Stimulation Unconventional Reservoirs ITBA