7/21/2019 sustaining conductivity.pdf http://slidepdf.com/reader/full/sustaining-conductivitypdf 1/14 SPE 98236 Sustaining Conductivity J.D. Weaver, D.W. van Batenburg, M.A. Parker, and P.D. Nguyen, Halliburton Energy Services Group Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, LA, 15–17 February 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Rapid loss of fracture conductivity after hydraulic fracture stimulation has often been attributed to the migration of formation fines into proppant pack or the generation of fines derived from proppant crushing. Findings presented in this paper suggest that diagenesis-type reactions that can occur between proppant and freshly fractured rock surfaces can lead to rapid loss of proppant-pack porosity and loss of conductivity. Generation of crystalline and amorphous porosity filling minerals can occur within the proppant pack because of chemical compositional differences between the proppant and the formation, and the compaction of the proppant bed due to proppant pressure solution reactions. This damage mechanism is applicable to all propped, fracture-stimulated wells; however, it is more significant in high temperature and high stress wells. It provides a possible explanation for the difference often observed between reservoir simulation of production after fracturing and actual production. Studies indicate as little as 25% of the initial proppant- pack porosity may remain after only 40 days at 300°F and 6,000-psi closure stress. The rate of porosity loss can be influenced by the surface treatment of the proppant, which indicates that some control of this process may be accomplished. Significance of this discovery has great impact on the economic life of a fracture-stimulation treatment. It affects the choice of proppant composition and post-fracture cleanup procedures, and adds an additional dimension to the appropriate laboratory determination of fracture conductivity that might be expected with the use of a particular proppant. Introduction Lehman et al . 1 reported that the use of surface-modification agents (SMA) to coat proppants used in propping hydraulic fractures resulted in sustained and more uniform production from wells. Fig. 1 taken from that publication shows the production decline curves from some of their data, and it does appear to show a significant change in decline rate compared to the use of untreated proppant. Initial use of this type of SMA treatment was promoted as a method to increase the conductivity of proppant owing to its ability to prevent close packing of the proppant, which can result in increased porosity and permeability of the pack by rendering the proppant surface tacky. Subsequent studies indicated that its use provided proppant-pack protection from fines infiltration and migration. This mechanism has been employed to explain the observations that sustained production results from the use of SMA on proppants. This is further substantiated by long-term results obtained in a single field study known for fines production problems. That both mechanisms are active has been well established through laboratory studies, but they alone do not completely explain the reduction in production decline rate as reported. A field study of SMA-treated proppant was reported to the Arkansas Oil and Gas Commission 2004 CBM Workshop tha disclosed long-term results on gas production. These were CBM wells in the San Juan Basin that typically required refracturing each year to produce at an economical rate. With the SMA-treated proppant, no refracs have been required, and as shown in Fig. 2, production has remained essentially constant for 5 to 6 years. This longevity was initially attributed to prevention of fines invasion into the proppant pack however, it is possible that there are additional mechanisms operational. Terminology Conductivity Hydraulic conductivity is simply the ability of a conduit to transmit a fluid. It is a function of the fluid properties and the conduit geometry. It is determined by measuring the pressure drop and fluid rate for a specific fluid through a conduit o fixed length with respect to the cross-sectional flow area. I the conduit is a pipe with fixed length, conductivity is usually presented by friction-drop-per-length tables for a specific fluid and is calculated using the Darcy-Weisbach equation. The key parameters in determining any hydraulic conductivity are conduit geometry, fluid rate, pressure drop, and fluid viscosity. Fracture Conductivity A fracture generated during a hydraulic-fracturing treatment is a fluid conduit and has conductivity. This conductivity is responsible for the difference in the pre- and post-fracturing
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Sustaining ConductivityJ.D. Weaver, D.W. van Batenburg, M.A. Parker, and P.D. Nguyen, Halliburton Energy Services Group
Copyright 2006, Society of Petroleum Engineers
This paper was prepared for presentation at the 2006 SPE International Symposium andExhibition on Formation Damage Control held in Lafayette, LA, 15–17 February 2006.
This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in a proposal submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to a proposal of not more than 300words; illustrations may not be copied. The proposal must contain conspicuous
acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
AbstractRapid loss of fracture conductivity after hydraulic fracture
stimulation has often been attributed to the migration of
formation fines into proppant pack or the generation of finesderived from proppant crushing. Findings presented in this
paper suggest that diagenesis-type reactions that can occur
between proppant and freshly fractured rock surfaces can lead
to rapid loss of proppant-pack porosity and loss of
conductivity. Generation of crystalline and amorphous porosity filling minerals can occur within the proppant pack
because of chemical compositional differences between the
proppant and the formation, and the compaction of the proppant bed due to proppant pressure solution reactions.
This damage mechanism is applicable to all propped,
fracture-stimulated wells; however, it is more significant inhigh temperature and high stress wells. It provides a possible
explanation for the difference often observed between
reservoir simulation of production after fracturing and actual
production.
Studies indicate as little as 25% of the initial proppant- pack porosity may remain after only 40 days at 300°F and
6,000-psi closure stress. The rate of porosity loss can be
influenced by the surface treatment of the proppant, which
indicates that some control of this process may be
accomplished.Significance of this discovery has great impact on the
economic life of a fracture-stimulation treatment. It affects thechoice of proppant composition and post-fracture cleanup
procedures, and adds an additional dimension to the
appropriate laboratory determination of fracture conductivity
that might be expected with the use of a particular proppant.
IntroductionLehman et al .1 reported that the use of surface-modification
agents (SMA) to coat proppants used in propping hydraulicfractures resulted in sustained and more uniform production
from wells. Fig. 1 taken from that publication shows the
production decline curves from some of their data, and it does
appear to show a significant change in decline rate compared
to the use of untreated proppant.
Initial use of this type of SMA treatment was promoted asa method to increase the conductivity of proppant owing to its
ability to prevent close packing of the proppant, which can
result in increased porosity and permeability of the pack by
rendering the proppant surface tacky. Subsequent studiesindicated that its use provided proppant-pack protection from
fines infiltration and migration. This mechanism has beenemployed to explain the observations that sustained
production results from the use of SMA on proppants. This is
further substantiated by long-term results obtained in a single
field study known for fines production problems. That both
mechanisms are active has been well established through
laboratory studies, but they alone do not completely explainthe reduction in production decline rate as reported.
A field study of SMA-treated proppant was reported to the
Arkansas Oil and Gas Commission 2004 CBM Workshop thadisclosed long-term results on gas production. These were
CBM wells in the San Juan Basin that typically required
refracturing each year to produce at an economical rate. With
the SMA-treated proppant, no refracs have been required, andas shown in Fig. 2, production has remained essentially
constant for 5 to 6 years. This longevity was initially attributed
to prevention of fines invasion into the proppant pack
however, it is possible that there are additional mechanisms
operational.
Terminology
Conductivity
Hydraulic conductivity is simply the ability of a conduit to
transmit a fluid. It is a function of the fluid properties and theconduit geometry. It is determined by measuring the pressure
drop and fluid rate for a specific fluid through a conduit ofixed length with respect to the cross-sectional flow area. I
the conduit is a pipe with fixed length, conductivity is usually
presented by friction-drop-per-length tables for a specific fluidand is calculated using the Darcy-Weisbach equation. The key
parameters in determining any hydraulic conductivity are
conduit geometry, fluid rate, pressure drop, and fluidviscosity.
Fracture Conductivity
A fracture generated during a hydraulic-fracturing treatment is
a fluid conduit and has conductivity. This conductivity is
responsible for the difference in the pre- and post-fracturing
The frozen, unconsolidated silica wafers were prepared using
wet silica flour with particle sizes of 325-mesh or smaller to
simulate unconsolidated formation faces of a soft formationand were molded into the proper shape and frozen to permit
cell assembly. The cells were then brought to an initial stress
of 2,000 psi and 180°F. An initial conductivity was obtained
by flowing through the proppant pack in the conventional
linear direction. Comparisons of conventional SMA with newSMA materials were performed by injecting the proppant pack
in the reverse direction with 3 pore volumes of treating fluid.
The initial conductivity was determined at 2,000-psi closurestress. After stable flow was achieved, flow from the core
wafers was introduced and the effluent fluid was captured to
examine for fines production. The conventional SMA and the
new SMA performed similarly, showing significantly reduced
fines after 48 hr compared to the untreated test (Fig. 20). The pack was then cycled from 2,000 to 4,000 psi several times
with a doubling in inflow rate with each cycle to try to
destabilize the pack. Fig. 21 shows the untreated proppantloses all conductivity very early in the test. However, the
SMA-treated proppants both show stable conductivity with
stress cycling.
ConclusionsGeochemical reactions can lead to rapid, dramatic loss of
porosity of proppant packs exposed to high temperature andstress conditions, leading to significant loss of fracture
conductivity. This mechanism is functional at lower
temperatures and closure stresses, but may be sufficiently slow
to not be a significant factor in production economics.The use of high-strength proppants may actually
exacerbate porosity-filling reactions by forming clay-like
minerals. This may partially mitigate the advantage of usingstronger proppants. Additional studies are needed to
understand the significance of this damage mechanism.Coating proppant with a hydrophobic film reduces the
action of water on the proppant and reduces the diagenetic,
geochemical reactions that lead to compaction.Coating both the proppant and the formation face with a
hydrophobic film provided by a new SMA appears to provide
the best protection against geochemical reactions that lead toloss of fracture conductivity due to porosity filling and
compaction mechanisms.
AcknowledgementsThe authors wish to thank the management of Halliburton for
their permission to publish this paper. Special thanks are
expressed to Gerard Glasbergen for conducting the production predictions and to Dr. Ray Loghry for his ESEM evaluations
and Mr. Bobby Bowles and Mr. Mike Gideon for theirdevelopment of testing protocols and management of long-
term conductivity testing.
References1. Lehman, L.V., Shelley, B., Crumrine, T., Gusdorf, M. and
Tiffin, J.: “Conductivity Maintenance: Long-term Results fromthe Use of Conductivity Enhancement Material,” paper SPE82241, 2003 European Formation Damage Conference, The
Netherlands, May 13-14.
2. API RP-61, Recommended Practices for Evaluating ProppanConductivity.
3. Weaver, J.D., Nguyen, P.D, Parker, M.A. and van BatenburgD.: “ Sustaining Fracture Conductivity,” paper SPE 94666, 6thSPE European Formation Damage Conference, ScheveningenThe Netherlands, 25-27 May 2005.
4. McDaniel, B.W.: “Conductivity Testing of Proppants at HighTemperature and Stress,” SPE 15067, 56th California RegionaMeeting, April 2-4.
5. McDaniel, B.W.: “Realistic Fracture Conductivities o
Proppants as a Function of Reservoir Temperature,” paper SPE16453, 1987 Low Permeability Reservoirs Symposium, DenverCO, May 18-19.
6. Parker M.A., and McDaniel, B.W.: “Fracturing Treatmen
Design Improved by Conductivity Measurements under In-SituConditions,” paper SPE 16901, 1987 Technical Conference andExhibition, Dallas, TX, September 27-30.
7. Cobb, S.L. and Farrell, J.J.: Evaluation of Long-term ProppanStability,” paper SPE 14133, 1986 International Meeting onPetroleum Engineering, Beijing, China, March 17-20.
8. Yasuhara, H., Elsworth, D., and Polak, A.: “A MechanisticModel for Compaction of Granular Aggregates Moderated by
Pressure Solution, Journal of Geophysical Research, Vol. 108 No. B11, 2530, November 18, 2003.
9. Schott, J., and Oelker, E.H.: “Dissolution and Crystallization
Rates of Silicate Minerals as a Function of Chemical AffinityPure & Applied Chem., Vol 67, No. 6 pp. 903-910, 1995.
10. Nguyen, P.D., Dewprashad, B.T., and Weaver, J.D.: “A NewApproach for Enhancing Fracture Conductivity,” paper SPE
50002, 1998 Asia Pacific Oil and Gas Conference andExhibition, Perth, Australia, October 12-14.
11. Dewprashad, B., Weaver, J.D., Nguyen, P.D., Blauch, M., andParker, M.: “Modifying the Proppant Surface to Enhance
Fracture Conductivity,” SPE 50733, 1999 InternationaSymposium on Oilfield Chemistry, Houston, TX, February 1619.
12. Weaver, J., Blauch, M., Parker, M., and Todd, B.: “Investigation
of Proppant-Pack Formation Interface and Relationship toParticulate Invasion,” paper SPE 54771, 1999 EuropeanFormation Damage Conference, The Hague, The NetherlandsMay 31-June 1.
13. Blauch, M., Weaver, J., Parker, M., Todd, B., and Glover, M.“New Insights into Proppant-Pack Damage Due to Infiltration oFormation Fines,” paper SPE 56833, Annual TechnicaConference and Exhibition, Houston, TX, October 3-6.
14. Nguyen, P.D., Weaver, J.D., Dewprashad, B.T., Parker M.A.
and Terracina J.M.: “Enhancing Fracture Conductivity throughSurface Modification of Proppant,” paper SPE 39428, 1998
Formation Damage Control Conference, Lafayette, LAFebruary 18-19.
15. SPE 48897, Surface-Modification System for Fracture-
Conductivity Enhancement, P.D. Nguyen, J.D. Weaver and B.TDewprashad. International Conference and Exhibition, BeijingChina, 2-6 November 1998.
Fig. 1—Test production data published3 by Lehman et al . for two adjacent wells stimulated with the same size
and type of fracturing treatment using 20/40 U.S. mesh ceramic proppant.
0 500 1000 1500 2000 2500
Well 1
Well 2
Well 3
Well 4
Well 5
Well 6
Well 7
Well 8
Well 9
Well 10
Well 11
Well 12
Well 13
Gas Production Rate, MCFD
Initial Post-frac Production(Frac Treatments, Mar 1997-Mar 1999) Production, May 2004
Fig. 2—Survey of wells fractured or refractured using SMA-coated proppant showing stability of production withtime. Uncoated proppant-fractured wells generally had to be refraced each year to sustain production.
Fig. 5—Alumina-based proppant (20/40 mesh, 2 lb/ft2) before and after exposure to 10,000-psi closure stress.
Micrograph on the right is of the proppant pack face that was forced against an Ohio sandstone core material.
Fig. 6—Ceramic proppant (20/40 mesh, 2 lb/ft2) after exposure to
10,000-psi closure stress at 250°F for 140 hr in 2% KCl solution understatic flow condition. Note the formation of porosity-filling debris thatdoes not appear to be derived from the proppant. This materialappears throughout the proppant pack.
Fig. 7—Series of micrographs showing the apparent embedment of a 20/40-mesh ceramic proppant into Ohiosandstone that occurred during conductivity testing at 6,000-psi closure stress and 225°F. Top left–Ceramicproppant grain. Debris surrounding the grain was found not to be Ohio sandstone or ceramic, but rather a new,high-in alumina material. Top right–Closeup showing how some of the new material is actually bonded to theproppant grain. Lower left–Area where a crystalline overgrowth has started growing. Lower right–Closeup of thecrystalline overgrowth.
Fig. 8—Plot showing the impact of closure stress on compaction derived bypressure solution and precipitation reactions.
Fig. 9—The impact of reservoir temperature on compaction derived bypressure solution and precipitation reactions.
Fig. 10—The impact of proppant size on compaction derived by pressuresolution and precipitation reactions.
Fig. 11—A compaction process by pressure solution mechanism.6 At the grain-to-grain contacts, the mineral
dissolves into the water film owing to the high localized stress, causing an increase in the solubility product ofthe mineral. The solute diffuses through the water film into the pore space where it becomes supersaturated andthen precipitates, resulting in reduced porosity.
Fig. 12—Schematic drawing showing how a packed fracture with uniform-sized proppant might undergodiageneic compaction resulting in loss of fracture width, and pack porosity and permeability.
Fig. 13—Fracture production simulation performed for a 1 mD, 300°F reservoir with a starting reservoir pressureof 3,000 psi using 10-mesh proppant with porosity filling data
8 from Yasuhara, et al .
Fig. 14—Authigenic crystal growth apparent near the edge of a craterformed by untreated ceramic proppant embedded into Ohio sandstone.
Fig. 15—High magnification of bottom of SMA-treated proppantembedment crater in Ohio sandstone showing no apparentcrystal growth.
Fig. 16—Crystal growth apparent in the crater formed in Ohiosandstone under an embedded, untreated quartz proppant grain.
Fig. 17—Apparent crystal growth protruding from ceramic proppant formed after 140 hr at 250°F and 10,000-psiclosure stess in 2% KCl against Ohio sandstone.
Fig. 18—Bottom of a untreated ceramic proppant embedment crater showing considerable diagentic activity afterexposure for 140 hr at 10,000-psi closure stress and 250°F in 2% KCl.
Fig. 19—Schematic of modified API linear conductivity apparatus for determining the effect of fines invasion fromthe formation into proppant packs.