hydraulic fracture optimization in unconventional reservoir

This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic implications on proppant selection.. Given the critical nature as wel

SPE 151128

Hydraulic Fracture Optimization in Unconventional Reservoirs

Pedro Saldungaray, SPE, Terry T Palisch, SPE, CARBO Ceramics Inc

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Middle East Unconventional Gas Conference and Exhibition held in Abu Dhabi, UAE, 23–25 January 2012

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s) Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s) The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied The abstract must contain conspicuous acknowledgment of SPE copyright

Abstract

Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs From tight gas, to oil and gas-producing shales and coal bed methane, resource plays rely on hydraulic fracturing for commercial viability

A primary goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of appropriate conductivity This objective is typically accomplished by drilling horizontal wells and placing multiple transverse fracs along the lateral Reservoir contact is optimized by defining the lateral length, the number of stages to be placed in the lateral, the fracture isolation technique and job size Fracture conductivity is determined by the proppant type and size, fracturing fluid system as well as the placement technique

While most parameters are considered in great detail in the completion design, the fracture geometry and conductivity receives lesser attention Some mistakenly anticipate that in extremely low permeability formations, hydraulic fractures act as

“infinitely conductive” features However, many factors that affect the realistic conductivity of the fracture are poorly understood or overlooked This often leads to a less than optimal outcome with wells producing below the reservoir potential This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic implications on proppant selection The effects of transverse fractures, low areal proppant concentration and flow dynamics, are considered among other variables The theory behind this concept is presented and supported with case studies where it has been applied in the field to various unconventional reservoirs

Introduction

Unconventional reservoir fracturing is unique in several aspects when compared to fracturing conventional wells Very low to extremely low permeability, horizontal well geometries, multiple transverse fracs placed along a horizontal drain, and complex frac geometry - particularly in shales - all add to the complexity of designing and implementing fracture treatments For the remainder of the paper we are assuming that horizontal wells with multiple fracs are utilized in unconventional reservoir developments In order to optimize the stimulation treatment, the design process must attend to multiple parameters which can

be grouped into four broad categories:

Wellbore Placement and Lateral Length These parameters are driven by geology, in situ stress regime, reserves to be

developed per well, production rates to be handled by each individual well, future well intervention requirements, surface logistics and environmental impact The trend within most unconventional plays through the years has seen an increase in the

lateral length to maximize the reservoir contacted and reserves developed by each well (Figure 1) In most cases the main

restriction to lateral length is the capability of both current and future intervention in the wellbore This may include limitations on frac isolation equipment and perforating, as well as coiled tubing reach concerns This trend of increasing the lateral length has favorably impacted the economics of field developments and leaseholds, and reduced the environmental impact of development Lateral lengths ranging from 1,000 to in excess of 10,000 ft are common today [Rankin 2010]

Completion Hardware and Isolation Techniques The

industry has developed a wide variety of completion hardware and isolation techniques for Horizontal Multi-Fractured wells (HMF) From barefoot openhole wells to uncemented or cemented liners, ball-activated sliding sleeves to pump-down plugs and perf guns, as well as hybrid systems, each technique strives to maximize operational efficiency by placing the maximum amount

of stages in the minimum possible time Current multistage sleeve systems are capable of placing dozens

of stages in a continuous pumping operation, with the maximum limits being continually pushed Plug and perf techniques are only limited by the ability to pump the plugs and guns down the lateral In the Bakken, for example, operators are now routinely placing as many as

40 stages per lateral using combinations of sliding sleeve and plug and perf methodology [Rankin, 2010] In fact,

it is rumored that some are contemplating as many as 50 stages in the future

Fracture Spacing and Number of Fracs This subject

is largely dependent on the rock fabric and permeability

of the formation As spacing is reduced adjacent fracs

start to interfere with each other affecting production

while costs continue to increase due to the larger number

of treatments An economic evaluation dictates the

optimal spacing where the benefit of adding fracs is

balanced with the cost of the increased number of

fracture stages [Rankin 2010, Norris, 1998] Two

parameters can affect this interference First is the rock

fabric, or the tendency of the hydraulic fracture treatment

to generate complex fractures The higher the tendency

to generate a complex network of fractures, the greater

the optimal spacing will be between fractures In this

case one will tend to measure the effectiveness of the

fracture in terms of Stimulated Reservoir Volume (SRV)

In some shales it has been demonstrated that increased

SRV will yield higher production and EUR [Mayerhofer

2008] The flow capacity or conductivity of the fracture

network combined with the SRV provide an assessment

method to predict well performance and hydrocarbon

recovery

As the tendency of the formation to generate complex

fractures decreases, the optimal spacing between

fractures becomes more tightly correlated with reservoir

permeability and resulting fluid mobility in the

formation In reservoirs more prone to conventional

bi-wing planar fractures, a greater number of closely spaced

stages are required to recover reserves in lower

permeability reservoirs [Cipolla 2009] In general where

reservoir permeability is the determining factor, it is not

uncommon to see long horizontal drains with dozens of

fracs spaced 10s to 100s ft apart In the Haynesville

Shale (Figure 2) and Bakken (Figure 3), for example,

increasing the number of stages has led to increased production

Figure 2– Initial Production as a function of Lateral Length and Total Number of Frac Stages for one operator in the Haynesville Shale [Pope 2009].

Figure 3– Increasing lateral length as well as decreasing the spacing between fracture stages has yielded positive impacts on production, EUR and well economics [Rankin 2010].

Figure 1 – Average horizontal lateral length in the Louisiana

Haynesville Shale has shown a steady increase since development

began in 2007, and a corresponding increase in average IP [Pope,

2010].

0 2 4 6 8 10 12 14 16 18

0

500

1000

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4500

Aug 07 Nov 07 Feb 08 Jun 08 Sep 08 Dec 08 Mar 09 Jul 09 Oct 09 Jan 10

"Lateral  Length" and IP vs Time

<= Lateral  

Length, ft

IP =>

0 1 2 3 4 5 6 7 8 9 10

Lateral Length x # Stages / 1000

#2

#1

#4

#7

#5

#6

#3

Fracture Geometry and Conductivity The fracture geometry optimization involves defining the desired fracture half-length,

width and conductivity for maximized production While there are several optimization methods, all involve a relative comparison of the flow potential of the fracture to that of the reservoir, as described by the Dimensionless Fracture Conductivity (FCD) parameter below:

For steady or pseudosteady state flow in oil wells, several authors [Prats 1961, Cinco-Ley 1981and McGuire & Sikora 1960] have developed correlations that allow the engineer to use FCD to predict the benefits of the fracture stimulation, yielding a method that balances fracture half length and drainage area with fracture conductivity for stimulation design FCD is also used

to optimize the design of the fracture in such methods as the Unified Fracture Design [Economides 2002]

While the FCD concept and various related fracture optimization methods are well understood, many in the industry fail to identify the correct fracture permeability to plug into the equation correctly estimated at realistic (downhole) flow conditions [Palisch 2007] Given the critical nature as well as generally overlooked impact of fracture conductivity, the following sections will be devoted to describing the deficiencies of the laboratory procedures, as well as provide references to adjust reported conductivities to reflect more realistic conditions within an actual fracture in order to guide the proppant selection process

Fracture Conductivity

The concept of fracture conductivity is often overlooked as an important stimulation design variable in unconventional reservoirs For some, the presence of nano-Darcy rock does not intuitively lead to the need for high fracture conductivity However, while the fracture conductivity required to economically produce a horizontal well in an unconventional play and to improve hydrocarbon recovery will vary in different reservoirs, many engineers fail to recognize the conductivity requirements

to accommodate high velocity hydrocarbon flow in transverse fractures The pack conductivity for a given proppant is a function of the proppant particle size, strength, proppant grain shape (roundness and sphericity), embedment into the frac faces, fracturing fluid residue, fines migration, effective stress on proppant and fluid flow effects (non-Darcy and multi-phase flow) which can be very pronounced in the limited intersection between a wellbore and a transverse fracture When accounting for these effects, it is not uncommon for proppant pack reference conductivity to be reduced by two orders of magnitude [Palisch 2007 and Miskimins 2005] In the following sections the authors will review the standard testing methodology and deficiencies in more detail

Conductivity Testing and its Limitations In order to understand realistic conductivity, one must first understand how

conductivity is measured and reported The conductivity of the fracture represents the product of the permeability of the fracture and the fracture width, and can be represented by the following equation:

conductivity of proppants in the lab using the Cooke Conductivity Cell [API 1989] The procedure was modified through the years to include longer flowing times, replacement of steel shims with sandstone cores and testing at elevated temperatures In

2006 the International Organization for Standardization (ISO) set the current standard under number ISO-13503-5 [ISO 2006]

In 2008 the API adopted ISO-13503-5 under API-RP-19D, effectively replacing API-RP-61 [API 2008]

These standards set testing procedures for evaluating sand, ceramic media, resin coated proppants, gravel packing media, and other materials used for hydraulic fracturing and gravel-packing operations The objective was to provide a consistent

methodology for proppant conductivity testing and comparing proppant materials under comparable laboratory conditions

Recognizing the standard’s limitation given the differing conditions between lab and realistic downhole conditions,

API-RP-19D specifically states it “is not intended for use in obtaining absolute values of proppant pack conductivities under downhole reservoir conditions” [API 2008]

The current procedure consists of placing a representative sample of proppant at 2 lb/ft2 in the test cell between two Ohio sandstone wafers with a Young’s Modulus (YM) of 5 million psi The cell is heated to 150°F or 250°F (depending on proppant type) and stress is ramped at a prescribed rate to the first test point After 50 hours a set of measurements is made and the process can then be repeated at each desired stress, holding for an additional 50 hours at each stress Conductivity is calculated by applying Darcy’s Law from the pressure drop produced by a 2 ml/min 2% KCl flow stream through the proppant pack Conductivities measured using this test are normally reported in service and proppant company published literature and may be denoted as “reference”, “laminar”, “baseline” or “long term” conductivities The key testing conditions are summarized below:

• 2% KCl fluid pumped at 2 ml/min

• 2 lb/ft2 proppant loading

• Sample placed between Ohio Sandstone wafers with YM = 5.0 Mpsi

• Single stress maintained for 50 hr

• Temperature 150° F (for sand) or 250° F (for ceramics)

Although these standard conditions allow for comparable testing between proppants, they rarely represent the realistic

conditions in which proppant is placed in hydraulic fractures [Vincent 2009] As such, these procedures ignore many

parameters that affect the actual conductivity of the frac Further complicating matters, different proppant types may be

affected differentially by each parameter A brief description of the key effects is given below The interested reader can refer

to SPE 106301 for a full description [Palisch 2007]

Non-Darcy and Multiphase Flow effects The ISO/API test flow rate of 2 ml/min is not representative of actual flow rates in

a proppant pack This rate would equate to ~6 BPD in a fully perforated vertical oil well with a 50 ft tall bi-wing frac

achieving 2 lb/ft2 concentration, or ~15 MSCFD flowing at 1,500 psi and 250°F in a similar dry gas well The fluid velocities

resulting from more prolific wells will cause tremendous amounts of energy to be lost, which translate into additional pressure

for a single phase fluid and is dominated by the velocity-squared term [Forchheimer 1901] Interpreting this extra pressure

drop as a conductivity reduction typically shows a fracture conductivity impairment of 50 to 85% [Palisch 2007]

……… …(3)

Additionally, the fluid circulated in the ISO/API tests is a

solution of silica-saturated, oxygen free 2% KCl water In

reality oil and gas wells rarely produce 100% water, or

even a single phase fluid for that matter Instead, two or

three phases are typically present (oil, water and gas),

yielding a much more complex flow regime than tested in

the lab Multiphase effects have been described in many

ways by various researchers Lab data consistently

demonstrate that pressure losses in the fracture may

increase significantly when both liquid and gas phases are

mobile within the fracture This is typically attributed to

the highly inefficient flow regime that occurs when gas, oil

and water molecules move through the proppant pack,

each moving at different velocity In fact, some tend to

consider multiphase flow impacts as a multiplier to

non-Darcy effects since the impacts are most pronounced at

high velocity flow Unfortunately, significant pressure

losses are documented even when only small percentages

of a second phase are mobile within the fracture (Figure 4)

Proppant loading at 2 lb/ft 2 It is generally accepted that in most slickwater or hybrid frac stimulations, the effective

proppant loading achieved in the fracture is less than 1 lb/ft2 This means that the fracture is narrower than in the ISO/API test

In addition to directly impacting conductivity via the conductivity equation (fracture perm x fracture width), the much

narrower width produced by the reduced concentration also increases the fluid velocity through the pack for a given flow rate

This in turn exacerbates the non-Darcy and multiphase flow effects in the fracture If the fracture width is halved, and

hydrocarbon velocity is doubled, then non-Darcy pressure losses are increased by a factor of 400% (2 squared)

Embedment and Spalling The ISO/API test uses a sandstone core with a YM of 5 million psi Many shale and

unconventional reservoirs are significantly softer than these sandstone cores (e.g the Eagle Ford Shale has a YM of 1-3

million psi) Softer rock leads to a loss of width and conductivity due to both proppant embedment and formation spalling

The reduced width has the double effect of diminishing conductivity (directly proportional), and increasing fluid flow velocity

due to the smaller cross section of the resulting proppant pack As a consequence non-Darcy pressure losses will also be

increased

Temperature Effects As noted earlier, the ISO/API conductivity test is performed at 150°F for sand proppant and 250°F for

ceramic proppant The reason for this difference is primarily due to the known detrimental impact of higher temperature on

sand and sand-based proppants (i.e Resin Coated Sand) Specifically, as temperatures exceed 200°F, sand based products can

Figure 4– The impact of Multi-phase flow can be dramatic at very low fractional flow rates of liquid [Palisch 2007].

Increased Pressure Drop due to Mobile Liquid in Proppant Packs

-10 20 30 40 50 60

Fractional Flow of Liquid

0.75 MMCFD 0.25 MMCFD Trend

Increased Pressure Drop due to Mobile Liquid in Proppant Packs

-10 20 30 40 50 60

Fractional Flow of Liquid

0.75 MMCFD 0.25 MMCFD Trend

experience a significant decrease in conductivity (Figure 5) For example, an uncoated sand, when exposed to 250°F at 6,000

psi stress will lose 40% of its conductivity when compared to 150°F, and this loss jumps to nearly 80% at 300°F and 8,000 psi Coating the sand with a resin lessens the damage because the resin can encapsulate the crushed fines However, even resin coated sand loses 30% of its conductivity at 8,000 psi and 300° F Ceramic proppants are tested at 250° F due to their thermal stability These proppants are sintered at ~2,700°F and are engineered for improved sphericity, strength and thermal resistance Therefore, no correction is required when placing a ceramic proppant into higher temperature formations

Cumulative Conductivity Impact When all of these

effects are taken together, the overall impact of these

damage mechanisms on the conductivity at actual bottom

hole flowing conditions can be severe In fact, it is not

uncommon to see the overall loss of conductivity exceeding

90% (Figure 6) It should also be noted that while all

proppants experience these several orders of magnitude

reduction in conductivity, the individual damage

mechanisms can have different impacts on the various

proppant types [Schubarth 2006] While the above

conductivity damage is already severe, there are also other

downhole realities that can exacerbate the damage,

including long term conductivity degradation as well as

gel/fluid residue damage and many other mechanisms

[Palisch 2007, Barree 2003, Pearson 2001] Regardless of

the exact magnitude of these reductions, the bottom line is

that the realistic conductivity in all hydraulic fractures is

much less than measured in standard lab testing, and

reported in industry literature Further, if these reductions

are not accounted for when designing hydraulic fractures and/or selecting the appropriate proppant, significant production may

be deferred or in some cases not recovered in the existing completion [Blackwood 2011]

Proppant Selection in Unconventional Reservoirs

The most common completion in unconventional plays consists of a horizontal wellbore with multiple proppant fracs placed along it Despite the very low reservoir permeability driving FCD up, high conductivity proppant is still needed given the detrimental effects discussed in previous sections Additional to the conductivity considerations, there are several other issues that must be addressed when selecting the appropriate proppant for use in these multi-stage fracs in horizontal wells These include flow convergence in transverse fracs, proppant transport when low viscosity fluids are employed, and proppant crush

at the typical low concentrations employed

Figure 5 – The effects of temperature on conductivity for Sand-based proppants [Pope 2009].

Figure 6 – The cumulative reduction in conductivity due to several damage mechanisms not accounted for in the standard ISO/API test [Palisch 2007].

0

0.2

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1

150 deg F

200 degF

250 deg F

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20/40 Premium White Sand

Closure Stress, psi

0 0.2 0.4 0.6 0.8 1

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200 degF

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350 deg F

20/40 Premium RC Sand

1540 5720

685 4310

225 1410

85 547

0 1000 2000 3000 4000 5000 6000

ISO 13503-5 Test (Base Case)

"Inertial Flow" with Non-Darcy Effects

Multiphase Flow Lower Achieved Width (1 lb/sq ft)

Gel Damage Fines Migration / Cyclic Stress

Jordan Sand Lightweight Ceramic

Effective conductivities can be less than 2% of API test values

99%

reduction

98% reduction

Cumulative Conductivity Reductions

Using PredictK

Closure Stress, psi

Flow Convergence in Transverse Fracs Let’s reiterate

that the goal in unconventional plays is to place numerous

transverse fracs along a horizontal lateral, as opposed to

conventional plays which may exploit a single frac in a

vertical well Production into a horizontal wellbore from

an orthogonal fracture will exhibit linear flow in the far

field as it travels down the fracture(s) However, as the

fluids converge on the relatively small diameter wellbore

(Figure 7), the fluid velocities in that near wellbore region

increase dramatically In fact, if one considers a single

planar 100 ft tall vertical fracture, and places it fully

connected in a vertical well and transversely in a horizontal 6 inch diameter wellbore, the fluid velocity in the near wellbore

would be 127 times higher in the transverse fracture as compared to the vertical well Further, recall that velocity is a squared

term in the Forchheimer (see previous discussion) pressure drop calculation, therefore, the pressure drop in the transverse frac

could be over 16,000 times greater than in a fully connected vertical well This leads to the conclusion that it is practically

impossible to place enough conductivity near the wellbore in a transverse/HZ well to be fully optimized Completions in

unconventional resources will benefit from more conductivity near-wellbore in transverse fracs [Besler 2007, Rankin 2010,

Shah 2010, Vincent 2011, Economides 2000]

Proppant transport and placement via low viscosity fluids Proppant placement is governed by a series of mechanisms

involving the interaction between the fracturing fluid and proppant A number of issues have been investigated through time

that impact how proppant is transported into the frac and its final location in the created geometry Proppant density and size

have a determining impact on proppant settling, which in turn impacts where proppant will be placed in the frac

The simplest single-particle settling mechanism can be described by Stokes law, in which the velocity of a single particle

falling through a stagnant liquid medium can be described as follows:

…… ……….………(4)

Where vfall is the settling rate in ft/s, dprop is the average

particle diameter in inches, is the fluid viscosity in cp,

and prop and fluid respectively are the specific gravity of

the proppant and the fluid [Economides 2000] The

settling rate is directly proportional to the difference in

density between the fluid and proppant, and inversely

proportional to the fluid viscosity This last condition

makes settling an important consideration when pumping

low viscosity Newtonian fluids as are typically used in

HMF treatments conducted in dry gas shales While

Stokes Law does not fully describe the proppant transport

in hydraulic fractures due to the many additional

considerations for calculating settling rate, it shows two

components are directly controlled by the proppant:

proppant density and diameter While much attention is

typically given to proppant density, proppant diameter can

actually be of greater importance in a fracturing treatment

As stated in Stokes law, settling velocity is proportional to

dprop squared, thus having an exponentially larger effect on

settling rate than fluid viscosity As an example, despite

being more dense, a smaller diameter 40/70 2.65 ASG LWC/RCS/Sand particle settles slower than a 20/40 1.75 ASG Proppant

(Figure 8) Again it should be noted that while there are significant limitations of using Stokes Law to describe setting under

dynamic conditions in a slurry situation it does serve the purpose to illustrate how smaller and lighter proppant aid easier

placement It is therefore no surprise that the most popular slickwater proppants are currently 40/80 LWC and 40/70

Sand/RCS Extensive research and experimentation have been carried out to better describe and assess proppant placement and

can be referenced outside this paper [Palisch 2008, Dayan 2008, Mobbs 2001]

Figure 7 – Fluids flowing within the hydraulic fracture in horizontal wells must converge into an extremely (relatively) small area as they cut transversely with the wellbore [Shah 2010]

Figure 8 – Relationship between proppant density and proppant diameter on settling rate in 2% KCl [Palisch 2008]

Proppant crush at low concentrations The typical low proppant concentrations pumped in waterfracs often designed for

unconventional gas reservoirs can result in a low areal concentration being placed in the frac Values between 0.25 and 0.50 lb/ft2 are typical and much lower than the 4.00 lb/ft2 load used in ISO 13503-2/API-RP-19-C crush test, or the 2 lb/ft2 used in the standard ISO/API conductivity test The impact of these low concentrations on proppant pack conductivity (due to the narrower width) were discussed previously in this paper However, an additional (and often overlooked) result of these narrower fractures is the impact on proppant crush When proppant grains are loaded into a crush cell, particles can be considered either interior or exterior grains Grains in the interior of the pack are “protected” due to their contact with six to twelve neighboring grains, thus providing uniform stress distribution on the individual gains However, exterior grains have fewer contact points leading to greater stress at the points of contact For this reason, exterior grains experience greater damage

in the crush and conductivity cells, and ultimately the fracture Therefore, as proppant pack width (and proppant areal concentration) decreases the exterior grains comprise a larger percentage of the total grains in the pack, thereby leading to

higher proppant crush [Palisch, 2009]

Some have also proposed partial monolayers as a means to boost conductivity, the idea being that voids between grains would provide open paths with infinite conductivity [Brannon 2004, Parker 2005] Using conventional proppants (Sand/RCS/LWC), a partial monolayer will occur at concentrations of <0.20 lb/ft2, where less than a single layer of proppant should occur While there is significant debate regarding whether partial monolayers can be reliably achieved over large portions of a created frac [Gidley 1989, Palisch 2008], even if they can be successfully placed many overlook the increased stress concentrated on individual proppant grains This will lead to higher crush, higher embedment, and ultimately loss of fracture width and conductivity

Various specialty proppants have been introduced to exploit the advantages of partial monolayers, as well as purportedly promote their placement Most of these new proppants are much lighter density (from 1.75 g/cc to nearly buoyant), formed from various substrates, including resin coated porous ceramic and/or walnut hulls, thermoplastics, nanocomposites, polymers and other resin or plastic components In many cases these proppants do not “crush” as conventional rigid particles do, but instead deform, which is one reason why they are typically only considered useful at low stress Caution should be exercised when employing these deformable proppants, however, as their usefulness is limited only to partial monolayers Independent testing has shown that if these deformable proppant grains are actually placed in a traditional pack whereby they come in contact with each other, the grains tend to “squish” together and become a relatively impermeable plug [Stimlab 2009-2010]

In summary, increased crush, concentrated stress on individual proppant beads and embedment (the latter two in partial monolayers only) occur when low areal concentrations are placed This phenomenon takes place regardless of whether the proppant is a Sand, Resin Coated Sand, Ceramic or specialty deformable proppant, constituting additional sources of frac width and conductivity loss one must consider for adequate proppant selection in unconventional plays

Proppant Selection Case Histories

When one understands the realistic conditions within the

proppant pack, and their impact on fracture conductivity, it

becomes apparent that the fracture flow capacity is not

optimized (i.e the FCD is much lower than anticipated) in

horizontal multistage fractures in unconventional reservoirs

Further, it means that in general, anything that can be done

to increase the conductivity of the fracture should yield a

corresponding increase in production While there are

many ways to increase the conductivity of a fracture, and all

should be considered when designing fracture stimulations,

one of the easiest and most common is to upgrade the

proppant size and/or type As one moves up the Proppant

Conductivity pyramid, fracture conductivity (and

production) improves (Figure 9) However, moving up the

pyramid typically carries with it an increase in completion

(proppant) cost Therefore, the decision to increase

conductivity must also involve an economic analysis, and ultimately will become an economic decision So the process for selecting proppant (as well as any design changes) must involve four steps

1 Calculate the conductivity of the fracture at realistic conditions

2 Predict the production performance achieved with each proppant

3 Evaluate the cost vs benefit and select the proppant that maximizes the economics of the completion

4 Review the actual field production benefits to ensure validity to the previous evaluations

The first two steps must typically be performed through the use of a fracture propagation model that is coupled to a reservoir simulator/model The model must be able to account for the realistic conditions of the fracture and the corresponding impact

Figure 9 – The Economic Conductivity pyramid showing the three Tiers of proppant 99% of all proppant can be placed into one of three Tiers As one moves up the Triangle, proppant performance (conductivity) improves [Gallagher 2011].

of fracture conductivity Step 3 can then be performed using the economic hurdles for the given situation; some production

simulators automate this function The last step is often the most overlooked step in the process, due to the significant activity

level required of most engineers involved with exploiting unconventional reservoirs The authors will present in the following

sections, several case histories from unconventional reservoirs in which proppant was selected considering the realistic

conductivity at bottomhole flowing conditions and the economic impact on the completion These cases illustrate the

robustness of the approach described above and demonstrate the production and economic benefits of placing enhanced

conductivity in ultra-low permeability formations

Case History 1 – Barnett Shale The successful development

of the Barnett Shale is considered by most to be the driving

force behind the success of today’s unconventional reservoir

exploitation Shortly after companies “cracked the code” for

successful completion practices (multistage fracs along

horizontal wellbores) in the early 2000’s, the Barnett Shale

became one of the hottest plays in the United States While

depressed natural gas prices have tempered the activity in the

play for the last several years, the Barnett still enjoys

widespread activity The Barnett Shale is a Mississippian-aged

shale located between 6,500 and 8,500 ft TVD It currently

covers as many as 15 counties in the Fort Worth Basin of north

Texas, and at its thickest point can be as much as 1,000 ft thick

The Barnett is a thermogenic reservoir and averages 4.5% Total

Organic Content (TOC) As is the case with all shale gas plays,

the primary challenge in the play is the ultra-low permeability of

<0.0001 md Numerous studies have been documented on the

completions practices in this shale gas play One such study

illustrated the benefits of increasing the conductivity of the

hydraulic fractures [Cipolla 2009] An actual Barnett Shale

completion was history matched and then sensitivities were

performed to several parameters including fracture conductivity

and fracture stage spacing The well of interest utilized a Tier 3

uncoated sand and was stimulated using a slickwater fluid

system The history match indicated that the realistic fracture

conductivity was ~2 md-ft, and showed that if the conductivity

were increased from 2 md-ft to 20 md-ft, the well would see a 1

BCF increase in the 15 year cumulative production (Figure 10)

In addition, the study also illustrated that the optimal staging

between fractures (stage spacing) was highly dependent on the

conductivity of the fracture (Figure 11) Namely, as the

fracture conductivity was increased, the optimal spacing

increased While all scenarios modeled would need to be

evaluated on a cost vs benefit basis, the study illustrated the

importance of accurately estimating the realistic fracture

conductivity, as well as the overall value of increasing the

conductivity

Figure 10 – Barnett well history match showing the potential impact of increasing the conductivity of the fracture The blue line represents actual well production [Cipolla 2009]

Figure 11 – The relationship between main fracture conductivity and spacing [Cipolla 2009]

SPE 119366

Potential Target of 1 Bcf over 15 years

Actual Well Production

Case History 2 – Haynesville Shale Using the learnings

from the Barnett, the industry opened up the shale gas

frenzy when the multistage fracturing in horizontal wells

was applied to the Haynesville Shale Its development

confirmed that this technology could be successful in other

shale plays The Haynesville Shale is a late-Jurassic age

shale that is found between the Cotton Valley Group and the

Smackover Limestone in East Texas and North Louisiana

It is a black, organic-rich shale with a TOC of 3-5% and

1.3-2.4 vitronite reflectance (Ro) Although the shale is

laterally extensive and variable, most of the development

occurs at depths between 11,000-13,000 ft, and in areas

where the total thickness is 150-400 ft While porosity is

moderate (6-12%), permeability is extremely low (5-800

nanoDarcies) The Haynesville Shale also has elevated

temperature (>300° F) and reservoir pressure (0.84-0.88

psi/ft) [Pope 2009, 2010]

Since most operators in the HV Shale initially adapted

their frac designs from their experience in the Barnett, the

primary fluid system of choice was either a slickwater or

“hybrid” design Small mesh (40/70 or 40/80) proppant was

primarily utilized given transport concerns with low viscosity fluids At realistic conditions (Figure 12), Tier 1 proppants have

two to twenty times the conductivity as Tier 2 and Tier 3 proppants, respectively [Pope 2009] However, despite the high temperatures and stresses, and this conductivity disparity, operators in the Haynesville shale have used tremendous volumes of all three Tiers of proppants This is primarily due to higher cost and limited availability of the Tier 1 proppants However, this large diversity of proppant usage has allowed for an opportunity to evaluate actual field performance comparing proppant types Once such study is comprised of a well “Set A” containing 56 wells operated by the same company within a 5 mile radius [Pope 2010] Twenty of these wells were known to contain Tier 1 40/80 Lightweight Ceramic proppant, while 36 offset wells were known to contain primarily a Tier 2 40/70 Premium RCS While there is significant debate over whether IP (initial production) is a good indicator of completion performance in shale gas plays, the authors illustrated that increasing the conductivity (from Tier 2 to Tier 1) of the fracture yielded nearly 50% increase in IP normalized for flowing pressure

and lateral length (Figure 13) As stated previously, when

comparing different completions, IP data alone can present concerns IP is just a snapshot in time and is an imperfect measure of success In addition, as a well is produced the stress on the proppant typically increases, therefore it is important to also look at the longer term performance of proppants A comparison of production for the same operator shows the Tier 1 wells are producing, on average, 20% more normalized production after 6 months than the Tier 2 wells

In addition, a smaller subset of wells “Set B” (10 Tier 1 and

19 Tier 2) have at least 12 months of production In these wells, the Tier 1 completions had produced 30% more normalized production than the Tier 2 The authors hypothesized that this increase may be indicative of the durability advantage of the Tier 1 proppant [Pope 2010]

In a follow up study, the above well sets were reanalyzed using an additional 12 months of data for each well set [Blackwood 2011] After normalizing for lateral length, the Tier 1 wells in “Set A” have produced over 20% more gas

Figure 12 – Realistic Conductivity Comparison at Haynesville/Bossier Shale conditions for several 40/70 proppants show that Tier 1 ceramic proppants (red and black lines) are far superior to Tier 2 and 3 proppants at 10,000 psi stress [Pope 2009].

Figure 13 – Cumulative frequency plots comparing Tier 1

(premium) proppant to Tier 2 (other) proppant, using IP data

that has been normalized to both the flowing pressure and

lateral length (right), show that increasing conductivity yields a

30-40% increase in production [Pope 2010]

Figure 14 – Per well projected average cumulative

incremental present value (PV10) of Tier 1 performance

versus Tier 2 performance, assuming $5/mcf gas price,

$60/bbl condensate and 10% discount factor Regardless of

whether projecting from “6 month” or “12 month” wells,

there is tremendous value to upgrading the conductivity and

the incremental investment pays out in less than 2 months

[Blackwood 2011].

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than the Tier 2 This represents an additional 340 MMCF of gas, or $2 million in value, per well Similarly, the Tier 1 wells

in “Set B” have produced an average of 39% more gas (or 500 MMCF gas) per well than Tier 2 wells That represents nearly

$3 million in incremental present value, and a tremendous return on the investment required to upgrade to Tier 1 proppant

The authors also performed hyperbolic decline curve analyses on the updated production, projecting recovery out to 20 years

For the two well sets, it is estimated that the Tier 1 wells will produce an average of 1.2-1.6 Bcf additional gas over the Tier 2

wells, and generate $4 – 5 million in incremental value over 20 years, and pay out the additional investment in proppant in less

than 2 months (Figure 14)

Case History 3 – Eagle Ford Shale The Eagle Ford formation is an Upper Cretaceous deposit in the Gulf Coast region of

South and Central Texas It has been recognized for many years and considered the source rock for several of the producing

reservoirs in South Texas However, it wasn’t until completion practices used in the Haynesville Shale were employed in the

Eagle Ford that it became economically viable to develop Since that time development has accelerated significantly, with

nearly 200 active rigs in late 2011 While it is typically referred to as a shale, the Eagle Ford is actually an organic rich

calcareous mudstone which is prevalent across 6 million acres spanning 20 counties The reservoir and geologic

characteristics can vary significantly across the play, with TOC ranging from 1-7%, depths from 6,000-13,000 ft TVD and

total thickness as much as 250 ft In addition, the reservoir fluids range from primarily oil in the northwest, to liquids-rich

condensate in the most active central portion, to dry gas in the deepest areas to the south Since development of this play did

not begin in earnest until the latter half of 2009 and into 2010, and given the geologic and reservoir variability across the play,

completion strategies are still being developed and optimized in the Eagle Ford However, one study was recently published

that documents the impact of fracture conductivity in Eagle Ford completions [Bazan 2010]

Two wells were modeled and history matched in this

study They are located in the condensate and gassy

areas of LaSalle County The depth of the “gassy” well,

Well A, is ~11,000 ft TVD, and of the condensate well,

Well B, is ~8,500 ft TVD Both wells were drilled with

4,000 ft laterals and contained 10 (Well A) and 12 (Well

B) stages Since these were some of the first wells

completed for this operator, additional data were

collected to assist in the history match, including

radioactive (RA) proppant tracers and microseismic

mapping While significant work was performed and

documented, two items of note will be discussed here

First, the fracture propagation and production match

confirmed that the realistic fracture conductivity, despite

using Tier 1 lightweight ceramic proppant, was much

lower than measured in the standard conductivity test

In Well A, the matched conductivity was ~2 md-ft,

while in Well B it was 1.75 md-ft Keep in mind that

these wells each produced in excess of 6 MMCFE per

day, so the stimulations and completions were

successful despite this low realistic conductivity

However, similar to the work presented earlier in the

Case 1 Barnett study, when proppants are placed into

downhole conditions, the conductivity can be damaged

quite severely Therefore, it is no surprise that when

sensitivities were run in these models, the impact of

conductivity was quite significant (Figure 15) A Tier 2

RCS would provide 75-100% greater cumulative

production than a Tier 3 Uncoated Sand, and the Tier 1

LW Ceramic provides an additional 20-50% over the

Tier 2, after just 3 years of production The condensate

well (B) enjoyed the largest increase, which is likely due

to the impact of multiphase flow and the corresponding

need for additional conductivity

Figure 15 – Upgrading from a Tier 3 Sand (blue) to a Tier 2 RCS (red) yields a 3 year increase in production of 75% (Well A-top) and 100%

(Well B-bottom) These increases jump an additional 20% (Well A) and 50% (Well B) when upgrading to a Tier 1 LWC [Bazan, 2010].