spe-147419-pa-psdfsdfd

Frac Packing: Best Practices and LessonsLearned From More Than 600 Operations

John Weirich, SPE, Jeff Li, SPE, and Tarik Abdelfattah, SPE, Baker Hughes Incorporated; andCarlos Pedroso, SPE, Petrobras

Summary

Frac packing is a completion technique that merges two distinctprocesses—hydraulic fracturing and gravel packing. The mainchallenge of a frac-pack completion is the successful creation ofhigh-conductivity fractures with the tip-screenout (TSO) tech-nique and the placement of proppant within those fractures and inthe annulus between the screen and wellbore wall. This is furthercompounded by having to do so in an ultra high-permeabilityenvironment, in which high fluid-leakoff rates are evident.

From 1997 to 2006, job data from more than 600 frac-packingoperations, representing an estimated 5% of the worldwide total,have been compiled into a database. This paper reviews well in-formation and key frac-packing parameters. Also summarized areengineering implementations and challenges, best practices, andlessons learned. Essential frac-pack design parameters that wereattained from the step-rate test (SRT) and minifrac test are eval-uated. These include bottomhole pressure, rock-closure time, andfracturing-fluid efficiency. Downhole pressure and temperatureare also discussed because of their importance to the post-comple-tion efficiency evaluation and fracturing-fluid-optimization phase.

Worldwide case histories are provided that demonstrate howto both deploy different frac-packing systems and pack the well-bore during extreme conditions with improved packing efficiencyand a higher chance of success.

Introduction

Deepwater exploration and production has developed during thelast 2 decades. There is a broadening of the geographic regions fordeepwater completions (Fig. 1). The vast majority of deepwaterreserves are concentrated in the Gulf of Mexico (GOM), westAfrica, Brazil, North Sea, and southeastern Asia. The potential toachieve significantly higher sustainable production rates, well lon-gevity, and cost reduction has been the primary driver for pursuingmost deepwater completions. There have been many differenttypes of completions in deep water, with frac packs and openholehorizontal completions emerging as the two dominant types (Vit-thal 2003). The type of application that was used has been found tobe area-dependent. In Brazil, the dominant completion type isopenhole horizontal gravel packing (OHHGP), which is shown inFig. 2a. In the GOM, 70% of completions are frac packs, which isillustrated by Fig. 2b. In west Africa both openhole completionsand frac packs are used. In general, frac packing has resulted in im-proved flow efficiency and has exhibited lower failure rates thanother sand-control methods (Vitthal 2003; Norman 2004). McLartyand DeBonis (1995), Tiner et al. (1996), and Ott and Woods (2003)provide a good overview of the technology development for fracpacking and other sand-control methodologies.

Frac-packing treatments are often applied to formations inwhich vertical permeability limits the application of horizontalwells or wells with multiple target zones behind the casing. Theproduction zones often feature high permeability and, in turn,high fluid-leakoff rates. In some cases, there may be two or morehighly permeable zones that are separated by a shale zone.

With the use of a TSO fracture technique to control fracturevolume, length/height/width control is a key objective of fracpacking. The TSO technique is necessary to generate fracturewidth in higher-permeability environments greater than 50 md.Coupled with the TSO method is a properly designed pumpingschedule that allows one to achieve an optimized fracture prop-pant-concentration profile and to gravel pack the casing/screenannulus in a single pumping operation. The frac-packing processmust be executed to combine TSO-fracturing and viscous-fluidgravel-packing technologies to be successful in terms of comple-tion reliability and economics.

TSO fracture treatments are applied to bypass near-wellboredamage, to provide vertical connection of laminated sands, and tostimulate low-permeability reservoirs. In high-permeability reser-voirs, short fracture lengths of several feet could bypass near-wellbore damage that is caused by drilling fluids, perforating de-bris, fluid-loss pills, and completion-fluid losses. TSO fracturetreatments also may be used to create longer fracture lengths tostimulate lower-permeability reservoirs or to create higher frac-ture heights.

Deepwater frac packs provide additional challenges to thecompletion engineer because of the higher rig costs and largerwork-string volumes. These are combined with the challenges offluid cool-down and achieving proper prediction of fluid perform-ance (Malochee and Comeaux 2003) and work-string lengthchanges.

The frac-packing process is often conducted initially with anSRT and a minifrac test, which are then followed by the mainproppant fracture treatment and gravel-pack operation. The pur-pose of the minifrac is to determine bottomhole treating pressure,fracture-closure pressure and time, fluid efficiency, and leakoffcoefficient. The SRT data can also be used to predict the fracture-extension and closure pressure, which may be confirmed by theminifrac test. The initial fracture design, derived from simulation,is then recalibrated with the minifrac-test results. The recalibratedmodel is then used to generate a revised proppant-fracturingpump schedule for the main treatment.

Unconsolidated-sand formations require high-quality pressuredata because of large variations of permeability and rock proper-ties. The analysis of surface-pressure data (pumping pressure)does not always provide an accurate determination of closurepressure, closure time, leakoff coefficient, and fluid efficiency forcases with high leakoff and fast closure times (Neumann et al.2002). However, “live-annulus” pressure readings will provide anaccurate estimation of the aforementioned parameters (Holcombet al. 2002; Neumann et al. 2002; Hale et al. 2004).

Well information and key frac-packing parameters reviewed inthis paper are derived from frac-packing jobs completed between1997 and 2006. Best practices, lessons learned, engineering im-plementations, and challenges related to the frac-packing processare also summarized. Field cases are provided, demonstratinghow to deploy different advanced frac-packing systems and howto pack the wellbore during extreme conditions with improvedpacking efficiency.

Frac-Packing Downhole Tools and Procedure

Deepwater completions have constantly challenged placementdesign. Pumping rates have been increased to handle longer treat-ment intervals or to maximize proppant placement. Therefore,

Copyright VC 2013 Society of Petroleum Engineers

This paper (SPE 147419) was accepted for presentation at the SPE Deepwater Drilling andCompletions Conference, Galveston, Texas, USA, 20–21 June 2012, and revised forpublication. Original manuscript received for review 19 March 2012. Revised manuscriptreceived for review 31 October 2012. Paper peer approved 19 November 2012.

June 2013 SPE Drilling & Completion 119

frac-packing service tools must be designed to meet such highrates and high-pressure pumping demands. The downhole frac-packing assembly should be developed to minimize or eliminatefluid loss post-treatment, reduce risk through the simplicity ofuse, increase reliability, provide redundancy and contingencyplanning, and reduce completion-cycle time.

Single-Trip, Single-Zone Frac-Packing System. As shown inFig. 3, a typical downhole assembly for frac packing consists of asump packer, seal assembly, gravel-pack screen, blank pipe, washpipe, shear safety joint, crossover tool, gravel-pack packer, andhydraulic setting tool.

The sump packer establishes the bottom base and provides thedepth correlation. It is set 10 ft below the lowest perforation andis usually set on wireline. The blank-pipe section connects thegravel-pack screen to the gravel-pack extension and provides areservoir of gravel-pack sand above the screen, thus ensuringscreen coverage in the event of pack settling. Both screen andblank pipe need to be centralized for even gravel distribution inthe annulus. The wash pipe is internal to the screen and blankpipe, and it serves to create a flow path at the bottom of the screenduring sand placement. The shear safety joint is between the blank

pipe and the gravel-pack packer assembly and below the sealboreextension. It allows for the emergency retrieval of the gravel-packpacker without pulling the screen assembly.

The crossover tool alternates the flow paths during gravel-packing operations. It allows fluids pumped down the work stringto “cross over” to the screen/casing annulus below the packer andbe squeezed to the formation. In circulation mode, the crossovertool allows return fluid to flow up the washpipe from below thegravel-pack packer and “cross over” to the work-string/casingannulus above the gravel-pack packer.

Various downhole frac-packing assemblies have been devel-oped that depend on the completion procedure. The following sec-tion briefly introduces several completion systems.

Single-Trip, Single-Zone Perforating/Frac-Packing System.

This system allows for a combined one-trip perforating and frac-packing operation that is aimed at minimizing completion timeand improving productivity. The perforating and frac-packingtools are run in the hole in a single trip with guns positioned ontarget depth. At post-detonation, the tool string is repositioned toplace the screens opposite the perforations, and remaining opera-tions are carried out as they would be for a single-trip, single-zonesystem.

Single-Trip, Multizone Frac-Packing System. This system pro-vides the ability to frac pack multiple zones in a single trip withcomplete zonal isolation before and after treatment. In addition,it provides the ability to provide selective or commingledproduction.

Each zone contains isolated gravel-pack screens with integralproduction sliding sleeves, a frac-packing sleeve for placing prop-pant, and an isolation packer. The equipment for all zones isassembled at the rig floor, and then a single gravel-pack servicetool is installed below the lowermost screened interval and con-nected through a concentric inner work string to the primary workstring above the top production packer. The entire assembly isnow run into the wellbore in a single trip. The service tool con-tains shifting tools that will selectively open or close the produc-tion sliding sleeves and frac-packing sleeves in each zone, thusallowing selective zonal isolation, treatment, or production.

Computer Simulator for Frac Packing

Because of the complexity and challenges of frac packing, theability to successfully model the TSO fracture volume and geo-metric shape and to design a proppant schedule to achieve an

Europe

North America

Latin America Africa, ME& Far East

Fig. 1—Global deepwater-completion areas with sand control.

OHHGP, 49.3%

CHGP, 15.4%

HRWP, 1.7%SAS, 2.8%ESS, 1.0%

Frac-packing, 29.8%

Total job # = 444

HWRP,19.6%

OHHGP,8.6%

Frac-packing, 71.8%

(a)

(b)

Fig. 2—(a) Percentage of various sand-control completions inCampos basin; (b) percentage of various sand-control comple-tions in GOM.

120 June 2013 SPE Drilling & Completion

optimized fracture proppant-concentration profile is intricate. Toaddress these issues, a computer simulator is used. Constantchanges in simulation-input parameters occur because of datagathering. Data are usually collected from field tests, such as aminifrac test, and on-site gauge readings. The simulation is thencalibrated to provide a more accurate estimation of overall frac-packing pumping volume, individual stage volumes, and fracture-growth behavior. Parameters that are accounted for include� Stress gradient� Rock properties� Permeability and porosity� Reservoir pressure� Leakoff coefficient� Fluid properties�Wellbore configurationsSeveral software packages that assist in the design and execu-

tion of sand treatments are available in the industry (Ott andWoods 2003). These software packages have several modules thatperform various functions. Some of these functions are intendedto� Calculate various engineering parameters� Simulate hydraulic-fracturing treatment� Simulate the gravel-packing displacement in three dimensions� Consider the surface equipment, work string, downhole sand-

control assembly, and wellbore geometry/profile to conduct thehydraulic calculation� Convert surface-treatment conditions to bottomhole conditions� Allow users to analyze the minifrac and SRT results to deter-

mine the fracture-closure pressure, fracture geometry, and fluid-leakoff coefficient� Present log data to identify treated layers and zones.

The simulator is a powerful analytical tool that can characterizethe physical phenomena of frac packing while considering down-

hole conditions. Its use results in better design, execution, andpost-treatment evaluation of the frac pack.

Overview of Frac-Packing Operations

Between 1997 and 2006, job data from more than 600 frac-pack-ing operations were compiled into a database. The data includewell details, reservoir data, formation-stress gradient, fracturetoughness, frac-packing pumping parameters, post-job reports,and job-problem reports. Well information and key frac-packingparameters from the database mentioned previously are illustratedin Figs. 4 through 13.

Frac-pack completions generally have a much deeper envelopethan OHHGP. The latest well- depth world record for a frac packin an extended well was recorded at a total measured depth(TMD) of 30,880 ft and a total vertical depth (TVD) of 11,591 ft.The depth envelope for frac packing is plotted in Fig. 4.

Figs. 5 and 6, respectively, plot the well-completion depth atthe top of perforation and the wellbore-deviation angle in both theGOM and Campos basin for three different sand-control methods[high-rate water pack (HRWP), openhole gravel pack (OHGP),and frac pack]. There is no significant difference in terms of wellvertical depth and deviation angles among the three different sand-control methods for the majority of wells. The deepest wellbore isapproximately 27,000 ft for frac packing. The reservoir pressuregradient in the GOM is relatively low and is less than 0.5 psi/ft forthe majority of the completed wells (Fig. 7). It is necessary to packsuch wells fully across the production intervals at a high pump rate.

The typical wellbore construction for the three differentgravel-packing completions in the GOM is usually composed of5-, 5 1/2-, 7-, 7 5/8-, or 9 5/8-in. production casing (Fig. 8). Theformation-stress gradient is depicted in Fig. 9, showing an averagevalue of 0.79 psi/ft. The fracture toughness is between 800 and

Circulation

Squeeze

Hydraulic Setting Tool, Tubing Pressure Actuated,Provides compressive force to set packer

Workstring, conveys assembly to bottom of wellbore

Retrievable Seal Bore Packer/Gravel Pack Packer,seals top of GP assembly to casing ID

Blank Pipe, provides area forgravel reservoir between top of screen & slurry exit ports

Shear Safety Joint,provides straight Pull disconnect for remedial operations

Gravel Pack Screen, Filters out gravel pack media

Sump Packer Seal Assembly, seals bottom of screen assembly into sump packer

Sump Packer Permanent Seal Bore,seals bottom of screen to casing ID

Washpipe provides a path for fluid circulation to thebottom of the screened interval

Crossover Tool, Diverts slurry from tubingabove GP packer to Casing Screen annulus below,Provides alternate path for washpipeflow below theGP packer to casing workstringannulus above

Fig. 3—Basic components of downhole assembly for frac pack.


10,000 psi/in.0.5 (Fig. 10). For the majority of the wells, the frac-ture toughness is 1,200 psi/in.0.5. The typical fluid-leakoff co-efficients range from 0.006 to 0.03 ft/min0.5 for sand and 0 to0.004 ft/min0.5 for shale sand. However, the fluid-leakoff coeffi-cients are varied (Fig. 11).

As Fig. 12 illustrates, pump rates for OHHGP and HRWP aremuch lower than those for frac packing. Pump rates for suchapplications are generally less than 10 bbl/min. In contrast, pumprates for frac packs can reach as high as 40 bbl/min. In the GOM,pump rates are between 15 and 40 bbl/min, with an average pumprate of approximately 15 bbl/min. In the Campos basin, pumprates are 10 to 40 bbl/min, with an average pump rate of approxi-mately 25 bbl/min. The frac-packing application envelope is con-stantly being enlarged in terms of pump rate and proppant volume.Today, pumping jobs at rates of 30 to 50 bbl/min with 100,000 to300,000 lbm of proppant are common.

The pack factor or packed-proppant mass per linear measure-ment depth is less than 100 lbm/ft measured depth (MD) forOHHGP and HRWP methods. However, the average pack factorin frac packing is approximately 640 lbm/ft MD in the GOM and1,120 lbm/ft in the Campos basin (Fig. 13). This indicates that theconductivity in frac-pack wells is higher than that in wells with anOHHGP or HRWP completion.

Fig. 14 shows the skin factors for the three different sand-con-trol methods. In the GOM, the average skin factor for frac packingwith underbalanced perforating is 0.44, whereas the same parame-ter has an average of 2.9 in wells with overbalanced perforating.Because the skin factor is not a linear parameter, it is converted tothe flow efficiency with a simple correlation between the skin fac-tor and the flow efficiency [efficiency¼ 7/(7þ skin)]. After theskin factor is converted to the flow efficiency, the averaged flowefficiency is then converted back to the skin factor. The average

0

5000

10000

15000

20000

25000

30000

350000 5000 10000 15000 20000 25000 30000 35000

TV

D, f

t

TMD, ft

GOM (Pourciau 2007)

GOM (Gillespie et al. 2005)

Gravel-pack from GOM

HWRP from GOM

Frac-pack from GOM

GOM (Van Sickle et al. 2006)

Gulf of Guinea (Cipolla et al. 2005)

Bohai Bay (Vickery et al. 2004)

Bohai Bay (Liu et al. 2006)

GOM (Ogier et al. 2011)

Frac-pack from Campos Basin

OHHGP Envelope(Farias et al. 2007)

Frac pack Envelope

Fig. 4—Frac-packing depth envelope across the world.

0

5000

10000

15000

20000

25000

30000

2 26 50 74 98 122

146

170

194

218

242

266

290

314

338

362

386

410

434

458

482

506

530

554

Ver

tical

dep

th@

top

perf

, ft

Job #

Fra

c-pa

ckin

g

OH

HG

P

HR

WP

GOM operation Campos Basinoperation

Fra

c-pa

ckin

g

Fig. 5—Vertical depth at the top of perforation for different sand-control completions.


skin factors shown in Fig. 14 were calculated with the aforemen-tioned method. This indicates that perforations conducted withunderbalanced conditions could improve well production. How-ever, individually, some wells with underbalanced perforating arestill estimated to have skin factors that are higher than those inwells with overbalanced perforating. More data are required toshow that underbalanced perforating is better than overbalancedperforating in frac-pack operations for well productivity (Neu-mann et al. 2002; Pourciau et al. 2005). The average skin factorfor OHHGP is 6.4; for HRWP and frac packing, it is 2.8 and 0.74,respectively. This indicates that frac packing has a higher comple-tion efficiency than the other two methods, and that OHHGP hasthe lowest completion efficiency among these cases. Similarly, inthe Campos casin, the averaged skin factors are 2.4, 2.1, and 24.1for HRWP, frac packing, and OHHGP, respectively. As men-

tioned in the Introduction, TSO fracture treatments applied in thefrac-packing process could bypass near-wellbore damage that wascaused by drilling fluids, perforating debris, fluid-loss pills, andcompletion-fluid losses. Therefore, the frac packing could resultin a lower skin factor. Thousands of successful frac-packing jobshave been completed across the world with enhanced packingtechnology and optimized through computer simulations. How-ever, every job has its challenges. Typical challenges and lessonslearned in frac-packing operations are discussed in the followingfour subsections.

Case Number 1—Single-Trip, Multizone Frac Packing in

Indonesia. In the Mahakham delta of Indonesia, wells are in rela-tively shallow waters at a depth of 200 to 260 ft to seabed. Withfive zones to be completed, installing conventional gravel-pack

0

10

20

30

40

50

60

70

80

90

100

1 25 49 73 97 121

145

169

193

217

241

265

289

313

337

361

385

409

433

457

481

505

529

553

Dev

iatio

n an

gle,

o

Job #

Fra

c-pa

ckin

g

OH

HG

P

HR

WP

Fra

c-pa

ckin

g

GOM operationCampos Basin

operation

Fig. 6—Wellbore-deviation angle for various sand-control completions.

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

1 25 49 73 97 121

145

169

193

217

241

265

289

313

337

361

385

409

433

Res

ervo

ir pr

essu

re, p

si/ft

TV

D @

per

f

Job #

Fra

c-pa

ckin

g

OH

HG

P

HR

WP

Fig. 7—Reservoir-pressure gradient for various sand-control completions in the GOM.


completions would consume up to 30 rig days. To reduce thecost, the operator applied the single-trip, multizone frac-packingtechnology (Banman et al. 2008). In the case to be discussed, a9 5/8� 3 3/4-in. single-trip, multizone system was selected forthe well completion. Since 2005, more than 20 wells were com-pleted with this technology. The longest bottomhole-assembly(BHA) length was 3,563 ft, completing up to six zones in one trip.

“A trip” is defined in this paper as “a work string” with anyBHA running in and pulling out of the hole. An electric-line (EL)trip is defined as one-half of a trip. For a typical five-zone stack-pack operation, described by Banman et al. (2008) and Suryanadaet al. (2010), 14.5 trips are needed with the service string, whereasonly 3.5 trips are needed with the single-trip, multizone system.

Fig. 15 shows the completion time per treated zone and thenonproductive time (NPT) related to the single-trip, multizonesystem. The relative NPT is defined as the percentage of total

NPT during the total completion time. The average completiontime per treated zone is approximately 29 hours. The total com-pletion time is defined as the duration between deploying thesump packer with EL and laying down the service tools on the rigfloor. For the analyzed jobs in this paper, 69 days were taken tocomplete a total of 60 zones with the single-trip, multizone sand-control system. When compared with the conventional stackedsand-control operation, 140 rig days (67%) were saved, resultingin significant cost saving.

A few lessons were learned during the frac packing of thesewells. In the early stage, to complete one of the wells, the operatornoticed that the debris plugged the holes around the hollow-steelcarrier when deploying large and long tubing-conveyed perforat-ing (TCP) guns. Computer modeling predicted that the TCP as-sembly run in this well would create an underbalanced conditioninside of the hollow-steel carrier resulting from the displacement

0

2

4

6

8

10

12

14

16

0 50 100 150 200 250 300 350 400 450 500

Cas

e si

ze, i

n

Job #

OHHGP

HRWP

Frac-packing

Fig. 8—Caseing size for various sand-control completions in the GOM.

0.0

0.2

0.4

0.6

0.8

1.0

1.2

444402369327384Job #

Str

ess

grad

ient

, psi

/ft

Fig. 9—Formation-stress gradient for frac packing in the GOM.


of the air with the completion liquid. To reduce the risks associ-ated with this dynamic process, the completion fluid is now circu-lated into the casing annulus inlet and circulated out through thecasing annulus outlet while the TCP guns are deployed. The oper-ator now uses this method as a standard procedure to avoid plug-ging the hollow-steel carrier. In addition, to mitigate formationinflux and potential well-control issues resulting from detonationdynamics and resultant fluid displacements, the work string isreciprocated immediately after the guns are fired. Also, conduct-ing a dynamic two-phase-flow analysis is a standard procedure toensure that this dynamic underbalanced condition is manageable.

Managing debris and keeping the hole clean during all stagesof the frac-packing process are crucial to completing the well suc-cessfully and minimizing NPT. As discussed previously, the de-

bris could plug the hollow-steel carrier if the hole is not clean. Inaddition, long TCP guns could generate considerable steel debrisafter firing (Banman et al. 2008). Cleaning this debris with a dedi-cated tool is essential to ensure that subsequent operations aretrouble-free. A scraper tool combined with a downhole-debrismagnetic tool, which is shown in Fig. 16, could be used to cleanthis type of debris. Sometimes, junk baskets are used to cleanlarge rock chips, blowout preventers’ (BOP) annular-bag rubber,and metal chips. Debris could also cause the downhole servicetools and seals to malfunction, resulting in higher NPT. In onefrac-packing completion, damage to the service-tool collets wasobserved, which led to unexpected downtime. Subsequent slick-line operations revealed BOP annular-bag rubber debris, whichwas left during the drilling stage. As a result, the annular bags are

0

2000

4000

6000

8000

10000

126 150 174 198 222 246 270 294 318 342 366 390 414 438Job #

Fra

ctur

e to

ughn

ess,

psi

/in0.

5

Fig. 10—Fracture toughness for frac packing in the GOM.

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0 100 200 300 400 500 600

Flu

id le

akof

f coe

ffici

ent,

ft/m

in0.

5

Job #

For sand

For shale sand

GOM operation

Campos Basinoperation

Fig. 11—Fluid-leakoff coefficients for frac packing.


replaced for each single-trip, multizone completion as a standardprocedure. Higher NPT with both Well 6 and Well 9 (Fig. 15)was a result of downhole debris.

As discussed by Banman et al. (2008) and Suryanada et al.(2010), the shearable safety joint above the isolation packer wasseparated resulting from shrinkage of the blank pipe in a longtreated interval. A study indicated that the shearable safety jointparted because the completion fluid cools the assembly, causingshrinkage of the blank pipe; when combined with the effects ofdifferential pressure, the joint separated. To remediate this forsubsequent well completions, an extra isolation system is used ina long zone. Tubing movement and force analysis are conductedas a standard procedure to evaluate the temperature-change effecton the BHA length and to determine whether an extra isolationsystem is needed.

In summary, after experiences with the first two wells, theoverall NPT dropped from 40 to 7%. As shown in Fig. 15, the ma-jority of NPT in the first well completion was associated withpulling the service tool to the surface. In the second well, the ma-jority of NPT was caused by the shearable safety-joint separationand subsequent remediation. The additional NPT in both Well 6and Well 9 was caused by downhole debris.

Case Number 2—Single-Trip, Multizone Frac Packing in

India. This case study discusses two vertical offshore wells inthe Bay of Bengal, India. The water depth is approximately 2,300ft. The wells were drilled and completed with a 9 5/8-in. casingwith the single-trip, multizone system. The system was intendedto frac pack five zones with a total BHA length of approximately1,100 ft. The single-trip, multizone completion schematic for one

0

5

10

15

20

25

30

35

40

45

50

1 25 49 73 97 121

145

169

193

217

241

265

289

313

337

361

385

409

433

457

481

505

529

553

577

Pum

p ra

te, B

PM

Job #

Fra

c-pa

ckin

g

OH

HG

P

HR

WP

Fra

c-pa

ckin

g


operation

Fig. 12—Pump rate for various sand-control completions.

0

1000

2000

3000

4000

5000

6000

7000

1 25 49 73 97 121

145

169

193

217

241

265

289

313

337

361

385

409

433

457

481

505

529

553

577

Pac

k fa

ctor

, lbm

/ft M

D

Job #

Fra

c-pa

ckin

g

OH

HG

P

HR

WP


operation

Fig. 13—Packed-proppant mass for various sand-control completions.


of the wells is shown in Fig. 17. The detailed operation informa-tion is summarized by Joseph (2010).

It is very interesting to compare the challenges and lessonslearned between this case and Case Number 1, because both use asimilar system.� At the time, this project involved the largest amount of sand

pumped into a single zone with a single-trip, multizone system:148,000 lbm of sand at a pump rate of 45 bbl/min. In addition, atotal of 260,000 lbm of 16/20 sand was pumped in the five zonesof Well 2.� Wellbore debris caused the frac sleeve to malfunction when

treating Zone 3 of Well 1. The same problem occurred when treat-ing Zone 1 of Well 2. Both incidents resulted in extra remediation

–10

0

10

20

30

40

50

60

70

80

90

1

Ski

n fa

ctor

Well number

Underbalanced perforation

Overbalanced perforation

Frac-packing

OHHGP HRWP

Averaged skin = 0.44 withunderbalanced perforation

Averaged skin = 2.9 withoverbalanced perforation

Averaged skin = 2.8

Averaged skin = 6.4

Frac-packing

OHHGP

HRWP

Campos BasinOperation GOM Operation

Averaged skin = 2.1

Averaged skin = 24.1

Averaged skin = 2.4

11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161 171 181 191 201 211

Fig. 14—Skin factor with various perforation conditions.(Data were compiled from Hannah et al. 1994; Petit et al. 1995; Stewart et al. 1995; Neumann et al. 2002; Ott and Woods 2003; and Pourciauet al. 2005.)

0

20

40

60

80

100

120

140

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15Well

Com

plet

ion

time

(Hou

rs/z

one)

, NP

T, %

Completion timeNPT

Fig. 15—Completion time and NPT analysis for select single-trip, multiple-zone completions in Indonesia.

Brush

Magnet

Stablizer

Bit

Fig. 16—Well-cleaning BHA in Indonesia.


trips. The NPT exceeded 40% for both operations, caused by sig-nificant wellbore debris, frac-sleeve malfunction, and downholeleaks. This is very similar to the NPT in Case Number 1 for thefirst two wells’ operation caused by the “learning-curve” period.After the “learning-curve” period, NPT could be reducedsignificantly.� Case Studies 1 and 2 indicate that wellbore-debris cleaning,

leak diagnosis, and associated contingency planning are criticalaspects to the success of a single-trip, multizone operation.� Pressure and temperature downhole memory gauges were in-

stalled in the service tool for these two wells. Information

obtained was valuable for the post-job analysis, helping identifythe TSO and net pressure, and for evaluation of the frac-packingdesign. Furthermore, a tracer log was performed to identify fracgeometries and to help further calibrate the frac simulation.

Case Number 3—Two-Zone Stack Frac Packing in GOM. Adeviated well on the continental shelf of the GOM (with a 54-ftwater depth) was drilled and completed with 5-in. casing. Thetotal MD of the well was 10,650 ft. There were two perforatedzones at 10,372 to 10,434 ft (62 ft) and 10,256 to 10,296 ft (40 ft).

DescriptionDepth

(mBRT)

CIW - SSMC Tubing Hanger

Depths are bottom of equipment unless specified otherwise

Isolation Packer

Wire wrap screen

Isolation Packer

Indexing Muleshoe

Isolation Packer

1835.02

2027.37

2076.64

9-5/8" Packer1825.59

Wire wrap screen

Wire wrap screen

4.1/2" Tubing

Sump packer w/ Seal Locator Assy

Isolation Packer2125.46

Wire wrap screen

Wire wrap screen

Isolation Packer1888.37

2160.22Zone 5

Zone 4

Zone 3

Zone 2

Zone 1

Fig. 17—Schematic of single-trip, multiple-zone completion in India.


Both intervals were within a 45�-deviation angle. The operator

decided to use the conventional stack frac-packing technology toperforate and frac pack in those intervals. The completion sche-matic is shown in Fig. 18.

The sump packer was deployed with an EL and set at 10,431ft. The perforation guns were deployed with a wireline to perfo-rate the lower zone. The guns were stuck a few times, whichresulted in extra fishing trips and a setting bull-plug trip. After theguns finally fired, a separate hole-cleaning trip was made. Subse-quently, acid was spotted and squeezed into the formation. Theminifrac and SRT were conducted. With these calibration tests,the main frac-packing treatment was redesigned and executedaccording to plan. The TSO was achieved.

For the top interval, the operator decided to use a TCP methodto deploy the perforation guns, eliminating the problems encoun-tered on the lower zone when the guns were deployed on wireline.After the well was cleaned with a 2 7/8-in. work string, the frac-pack BHA was run in hole. Subsequently, acid was spotted andsqueezed into the formation, and the minifrac and SRT were per-formed. The frac pack was bullheaded from the surface. The sec-ond interval treatment took a total of 46 hours. The lower-zonetreatment took 52 hours. On average, 49 hours per zone was takento treat each interval. As a comparison, in Case Study Number 1,it took 29 hours per zone in the wells with relatively similar depth(approximately 10,000 ft), but five zones were treated in a singletrip.

Case Number 4—Three-Zone Frac Packing in Campos Basin.

The Roncador field, a giant ultradeepwater field discovered in1996, is in Campos basin, Brazil, 115 km from Rio de Janeiro.The extent of the field was approximately 111 km2 with waterdepths ranging from 1500 to 2000 m. Because of its large exten-sion, high volume of oil in place (3.3 billion bbl of provenreserves), different fluid properties, and variations in geologicalcharacteristics, the development strategy was phased in fourmodules.

Module 1A started production in 2002 with 12 wells (9 pro-ducers and 3 injectors). At the end of 2007, the second phase ofModule 1A and Module 2 started production through 29 wells (18producers and 11 injectors). Module 3 will produce from 17 longhorizontal wells (11 producers and 6 injectors).

Roncador’s main reservoirs are unconsolidated turbidity sand-stones from the Upper Cretaceous (Maastrichtian), thus demand-ing a sand-control method to be produced. These main reservoirsare divided into two areas, separated by a massive fault. The dep-ositional model has been interpreted as a complex turbidity sys-tem, mainly represented by channels, lobes, and over bank faces.The hanging wall block (Module 1A) has a net thickness of 240 min stratified sandstones, which was the main reason for develop-ment with vertical/deviated multiple-completion wells. In contrast,the footwall block has been characterized by a single sandstonewith no stratification, which was the main reason for developmentwith horizontal wells. The wells had lateral lengths ranging from500 to 1000 m.

The Maastrichtian reservoirs (which are locally named Ronca-dor Sandstones) are subdivided into three main hydraulically dis-tinct stratigraphic intervals, referred to as Roncador 2, 3, and 4.These three intervals have different permeabilities and fluid vis-cosities and, therefore, different mobilities. Furthermore, theenhanced-oil-recovery method for this module is water injection.Because of these factors, the module was expected to have differ-ent water-breakthrough times for each interval. This is the mainreason that the hanging wall block of Roncador field was devel-oped with three selective stacked frac packs. In fact, the need forthis selectivity pushed the development of this technology thatwas first used in 1999 (Rovina et al. 2000).

The shale separating the lower (Roncador 4) and middle inter-val (Roncador 3) was less than 7 m long (Fig. 19a) in MD (5-mTVD), posing a risk of possible communication between the inter-vals if hydraulic fracturing was to be performed. This was con-firmed by simulation. If the fractures were to communicate, all theefforts to develop and install a selective completion in Roncadorwells (in both producers and injectors) would have been inefficient.The use of radioactive tracers was not allowed by the Environmen-tal Protection Agency and, therefore, to confirm this hypothesis, atemperature log was used to identify the fracture height.

In general terms, the new sequence was to run a base tempera-ture log, perform a minifrac with the same volume expected in themain treatment pad, repeat the temperature-log run to identify thefracture height, and then decide between either continuing with afrac pack or dropping the sand-control method to an HRWP, thuspreserving selectivity.

Fig. 19b shows one example of the temperature-log interpreta-tion. The graph displays the perforations (the thick red bar), and,on the right side, the temperature inflections (dash lines and dotlines) show a very well-defined top and bottom of the fracture. Thefracture is on the limits of the perforations. Both upper and lowershales, identified by gamma ray and neutron-density logs, wereable to restrict fracture growth. Also, the shale in the middle of theperforations did not impose any restriction to fracture growth.

This procedure was repeated in three wells, showing similarresults. This indicated that the top and bottom shales were stiffenough to contain the fracture propagation.

An interesting point to be observed is that the amount of fluidinjected, which can be inferred from the cooling effects read inthe temperature log, along the perforated interval during the cali-bration tests shows a good correlation with the permeability pro-file obtained with the nuclear-magnetic-resonance log. In this

10170' Packer

10199' Shear-out Safety Joint

10246' Screen

10284' Screen

10304' Isolation Packer

10333' Shear-out Safety Joint

10366' Gravel Pack Screen

10386' Gravel Pack Screen

10424' SUMP Packer

Fig. 18—Two-zone stack frac pack in the GOM.


case, the better permeability was read at the bottom of the inter-val, where more fluid was injected. However, because thissequence added 60 hours to the normal procedure, it became aspecial procedure, applied only when specific information aboutthe fracture-height propagation was necessary.

Best Practices From Field Cases forthe Frac-Packing Process

Although it is important to effectively prevent sand production, itis equally important to do so in a way that does not hinder produc-tivity. The feasibility and success of frac packing a well dependon wellbore cleanup, completion fluids, completion tools andequipment, proppant and screen selection, work-string design,perforation, software/simulators, sand-control design/executionand post-treatment evaluation, and field-personnel experience.The best practices for frac packing are summarized in the follow-ing sections.

Completion Fluid

� Mechanical plugging is the most common cause of forma-tion-permeability damage. To minimize its effect, clean fluidsmust be used during drilling-fluid displacement, perforating, well-bore cleaning, and frac-pack treatment.� Dedicated filtration equipment must be used to filter the com-

pletion fluids before pumping them into the wellbore.� Brine is a common completion fluid. Proper brine fluid must

be selected on the basis of its density for well control, compatibil-ity with the formation rock matrix and other fluids, and the crys-tallization temperature for maximal storage and optimal operatingconditions.� Deepwater environments often present conditions for the for-

mation of gas hydrates. Computer models can be used to evaluatethe hydrate-equilibrium conditions for a variety of completionbrines.� Surfactants are often added to completion fluids to minimize

potential formation-damage problems associated with water block-ing, oil-wetting, clay control, fines migration, and emulsions. Theymust not be used indiscriminately, however, because they cancause additional damage as opposed to preventing it.

� Fluid-loss control is critical to the installation of the tool sys-tem for frac packing post-perforating. Fluid loss should be mini-mized but not necessarily stopped. The common methods forcontrolling fluid loss include reducing hydrostatic pressure andspotting viscous polymer gels or acid-soluble graded solids par-ticles. Some tool systems have mechanical isolation valves tomechanically control fluid loss.� Polymer-based fluids (linear gel and crosslinked gel) are of-

ten used for the main frac-packing treatment. Their propertiescould significantly affect fluid-loss control, pumping hydraulics,proppant delivery, frac packing, and formation damage. Thecrosslink time and stability time should be derived from the cool-est calculated work-string temperature. However, the crosslinkbreak time should be tested at a temperature closer to the bottom-hole static temperature after pumping has ceased (Malochee andComeaux 2003). The proper gel load should be selected on the ba-sis of the downhole temperature because of the gel degradation athigh temperatures.� In some deepwater completions, multiple fluids are used, in

which case each fluid should be evaluated individually. The fluidthat is considered “fit for purpose” should undergo evaluation(Javora et al. 2006) with the proper laboratory equipment and pro-cedures for on-site maintenance and handling.

Work String

� The work string is the hardware used to deploy packers anddownhole tools, and it is the conduit to circulate fluids during thefrac-packing process. Similar to drillpipe-design criteria, work-string design considers torque, drag, pipe stretch or buckling, andcasing wear caused by high metal-to-metal friction.� Hydraulic analysis (friction and pressure profile along well-

bore) for pumping various fluids throughout all completion proc-esses—including cleanout, displacement, perforation, washoutand frac packing—should be conducted for deep wells. This helpsensure that the maximal pump rate for a specific application canbe delivered without putting any added risk to the integrity of thework string, surface equipment, and downhole tools.� In cases when dynamic or transient process conditions (pipe

moving, BHA switching from squeeze/circulation position to the

Temperature Log

(a) (b)

Fig. 19—Multilogs information before and after the calibration test for Campos basin operation. (a) Gamma ray and neutron-density logs before the calibration test; (b) temperature logs after the calibration test.


reverse position, and gas kicking) are involved, transient hydrau-lic analysis should be conducted with a capable software (Banmanet al. 2008).� An internal abrasion-resistant drillpipe coating maximizes

pump rates while eliminating internal buildup of pipe scale, pipefailures, and the need for pickling pipe (Pourciau 2007).

Perforating

� There is not enough evidence to indicate that there are differ-ent effects on the performance of frac-packed completionsbetween underbalanced and overbalanced conditions in both theGOM and Campos basin (Neumann et al. 2002; Pourciau et al.2005). However, in the GOM, the top 10 cased-hole producingwells were perforated in an underbalanced condition with TCPguns (Ott and Woods 2003). Overbalanced perforating hasbecome the standard perforating technique for frac-packing opera-tions in the Campos basin (Neumann et al. 2002).� A good rule of thumb is that the screens should cover at least

10 ft above and below the perforated interval, to ensure coverage.� For a long perforation interval (more than 900 ft), the shrink-

age of the blank pipe resulting from the thermal effect should beconsidered, and additional isolation packers should be installed(Rovina et al. 2000).

Downhole Assembly

� Designing a reliable and robust downhole frac-packing as-sembly is very important for the whole operation. There are morechallenges for the downhole assembly when the multitreatedinterval gets longer and deeper, and the demand for larger vol-umes of proppant and high pumping rates becomes evident.� Service-tool movement from squeeze/circulation position to

the reverse position can apply a large drawdown pressure on theformation. This swabbing effect has serious implications on sandplacement and production from the target zones. The operationprocedures must be carefully planned and modified to eliminateexcessive tool reciprocation and to minimize the instantaneousswabbing effect. At the same time, keeping the hole in a “clean”condition is very important to ensure that the whole operation pro-gresses smoothly and successfully.� The annular clearance between the inside diameter and the

section below crossover tool (Fig. 3) down to the screen should beselected large enough (more than 0.75 to 1 in.) to minimize prop-pant bridging and to avoid premature sandout (Moreno et al. 2009).� It is important to maintain a balanced or overbalanced condi-

tion to avoid flowing unconsolidated sands before the placementof proppant into the perforations.

Proppant and Screen

� Proppants in a frac pack should provide an effective perme-ability contrast, maintain fracture conductivity without proppantcrushing, control sand influx and fines migration, and minimizeproppant embedment in soft rock formation.� In general, the proppant used in frac packing is larger than

that used for gravel packing. The proppant size should be selectedwith the formation-sand size analysis, and it is usually a multipleof the d50 formation-sand size (e.g., d50� 7 or 8).� Completions in deeper wells, with high fracture-closure

stresses, must use manufactured ceramic poppants because oftheir consistent spherical shape and higher strength. Ceramicproppants, because of their consistent shape, will provide a betterfracture conductivity.

Wellbore-Debris Cleaning

� With the field operations experiences, the greatest challengeencountered in frac packing is downhole-debris management.� Historical data indicate that as much as 30% of NPT during

completions is a result of debris left in the wellbore (Hern 2010).� There are a few options to manage the risks related to down-

hole debris. Applying high-viscosity gel slugs with high-density

completion fluid regularly sweeps the well system. The workstring should be rotated and reciprocated (Pourciau 2007) whensuch slugs are circulated, especially for a highly deviated or hori-zontal well. The debris is usually cleaned out of the well with aspecial tool (Hern 2010) (i.e., downhole casing scraper, downholedebris filter, downhole magnetic tool, or junk basket).

Calibration Tests (Minifrac and SRTs)

� Calibration tests provide fracture extension, closure pres-sures, and fluid leakoff, which are used to redesign the main frac-packing treatment to achieve TSO. Modern fracturing engineeringsoftware could help the completion engineer analyze the results ofthe calibration tests and determine key parameters.� True live bottomhole pressure is critical to evaluate the frac-

ture-closure pressure. It is more challenging to interpret minifrac-test results in soft and high-permeability formations than it is inlow-permeability hard rocks. In general, the G-function plot

(Smith et al. 2002) or a derivative plot ISIP� tdBHP

dt

� �, where

ISIP is the instantaneous shut-in pressure, BHP is the bottomhole

pressure, t is the time,dBHP

dtis the bottomhole pressure change

rate and * is the multiplication operation in the original content.(Neumann et al. 2002) gives a good indication of closure pointduring a minifrac analysis.� In the Campos basin, the minifrac test is needed only for the

calibration test (Neumann et al. 2002). However, in the rest of theworld, both minifrac and SRT are needed. The determined exten-sion pressure and rate from the SRT could help identify the clo-sure pressure from the minifrac because the fracture-extensionpressure is an upper bound on the fracture-closure pressure.� Adding pH-control additives into the SRT fluid enhances the

reservoir’s ability to return to its preminifrac leakoff condition.Therefore, it results in a higher success rate for TSO during themain frac-packing treatment and a higher net-pressure gain fortreatments. Using a pH-control-additive technique could result in60% higher net-pressure gains than in treatments without a pH-control additive (Holcomb et al. 2002).� The injection fluid during minifrac tests could affect the

leakoff characteristics of the main frac-packing treatment (Bruceand Jacot 2000; Smith et al. 2000; Holcomb et al. 2002). Thiseffect should be considered for the main-treatment design withthe proper software (Bruce and Jacot 2000). Injecting non-crosslinked gel with added higher breaker concentrations andcontrolling pH in the SRT could recover the reservoir leakoffcharacteristics.

Surface Equipment

� There are four basic types of equipment used for the frac-packing treatment—mixing and blending, pumping, proppant han-dling, and monitoring/control.� Skid-mounted equipment has become very popular and

somewhat of an industry standard because it provides higherdeployment versatility. All equipment should be customized tomeet a specific set of design parameters.� A dedicated, fit-for-purpose stimulation vessel and its crew

members are also critical to the success of the frac-packing opera-tion. The vessel should have enough space to accommodate fracequipment, mixing and blending equipment, storage proppant andliquid equipment, and a pumping and control/monitoring room forthe operation.

Frac-Packing Design and Simulation

� Achieving TSO is the key for successful frac packing inhigh-permeability formations. TSO fracturing relies on a carefullytimed TSO to limit fracture growth and to allow for fracture infla-tion and packing.� The criteria for TSO in frac-pack design should include

designing to prespecified fracture length (25 to 50 ft) to optimizenear-wellbore conductivity; determining the pumping schedule in


terms of rate and proppant concentration; designing to achieve aminimal concentration per unit area; and maintaining pumpingpressures at less than critical maximal pressures.� TSO should be designed with modern fracturing software

with the calibration-test results and other rock mechanical proper-ties. The critical information needed for a frac-packing designshould include casing and work-string size, wellbore deviation,perforation-interval length, formation permeability, rocks Young’smodulus, mineralogy, bottomhole pressure and bottomhole tem-perature, water depth, and proppant size and type (Moreno et al.2009). With this information, a proper downhole completion-as-sembly tool (screen, blank pipe, and other components), packers,perforation system, and completion fluids can be selected.� A screenout may occur early if fluid leaks off to the forma-

tion faster than predicted. Conversely, a screenout may not occurduring the job if fluid leakoff is much slower than predicted. If aTSO is not achieved in the moderate- and high-permeability for-mation, a stimulated completion is not expected.� Laminated shales, greater than 3 m, are able to constrain

fracture-height growth at common pump rates (Neumann et al.2002). The laminated formations with multiple lobes and defini-tive shale breaks also present a challenge to interpolate data andmodel the fracture.� HRWP rather than frac packing should be used as a sand-

control method for thin and high-permeability formations. Cau-tion should be taken in using frac packs when water or unwantedfluid is very close to the treated intervals (Neumann et al. 2002).� Non-Darcy and multiphase effects should be considered in

the frac-pack design and proppant selection when said effects aresignificant (Vincent et al. 1999).

Post-Frac-Packing Evaluation

� After a frac pack is in place, it is important to evaluate theeffectiveness of the treatment. There are a few logging methodsthat include density log, dual-detector neutron log, and spectragamma ray or tracer logs.� The tracer log is the most common log method. Fracture

fluid and proppant could be tagged with different radioactive trac-ers. Tracer logs record spectral gamma ray data as a function ofdepth, and therefore, they can evaluate the distribution of thetagged materials along the wellbore. This allows not only the esti-mation of the total and individual packed-fracture heights acrossthe multizones but also the detection of the voids in the packs ifthey are present.� With the logging feedback, a decision could be made imme-

diately after the completion. When voids or plugged packs aredetected, remedial action can be taken to help optimize produc-tion and to prolong the life of the well.� Combining tracer logs with downhole pressure- and temper-

ature-gauge data allows one to quantify the fracture model interms of the exact screenout prediction, dynamic fluid-flow analy-sis, and annular-pack sand percentage; it is also possible to iden-tify all the major events taking place at downhole conditions,identify the time of their occurrence, and obtain explanations ofsome unexpected events (Sanford et al. 2010).

Conclusion

The well information and the key frac-packing parameters formore than 600 frac-packing jobs were reviewed. The historicalreview shows that the frac-packing methodology has beenimproved to pack the hole more efficiently and safely. The sum-mary of best practices and lessons learned and the engineeringchallenges and implementations of frac packing provide a goodguideline for future practice. In summary,• Frac packing can be successfully executed with reliable tools,

well-prepared plans and operation procedures, and dedicatedteamwork.

• Single-trip, multizone systems have been developed and arefield-proven. With the validation of these systems, it is possibleto perform frac-packing operations with less rig time and highreliability.

• The TSO is the key for a successful frac pack in high-perme-ability formations.

• Using a frac-packing simulator, updated with real-time data,and taking into account the parameters estimated from the cali-bration tests will help field engineers design, optimize, and exe-cute the frac-packing process.

• The minifrac test and SRT are essential applications, beforedesigning the main fracture treatment, because they assist inestimating important parameters such as fracture-closure pres-sure and time, fracture leakoff, and fluid efficiency.

• Real-time monitoring of the surface “live annulus” pressure,pump rate, bottomhole pressure, and sand-injection concentra-tion is crucial to understand the overall frac-packing process.

• Real-time monitoring of bottomhole temperature could helpdesign fluid breakers more efficiently.

• Cleaning the wellbore before frac packing and pumping high-quality fluids are important to ensure completion success.

• Models that analyze work-string torque and drag, frac packing,perforation, proppant/screen and fluids selections, wirelineoperations, fluid hydraulics, and debris cleanout are essentialfor the whole process.

Acknowledgments

The authors would like to express their appreciation to BakerHughes and Petrobras for the opportunity to present this paper.We also wish to thank Baker Hughes field-operation crews for theexecution of these treatments. We also wish to thank colleaguesNicholas Clem and Luly Stephens for their valuable input and thetime spent to edit the manuscript.

References

Banman, M., Delattre, E., Sofyan, M. et al. 2008. Single-Trip Multi- Zone

Gravel Packing—Field Case Study Within Total E&P Indonesie on

Handil, Bekapai, and Sisi Nubi Fields. Paper IPTC 12388 presented at

the International Petroleum Technology Conference, Kuala Lumpur,

Malaysia, 3–5 December. http://dx.doi.org/10.2523/12388-MS.

Bruce, R. and Jacot, R. 2000. The Effect of Fluid Loss During Fracture

Calibration Tests on the Main Treatment. Paper SPE 65624 presented

at the SPE Eastern Regional Meeting, Morgantown, West Virginia,

17–19 October. http://dx.doi.org/10.2118/65624-MS.

Cipolla, C.L., Shucart, J.K., and Lafitte, J.R. 2005. Evolution of Frac-pack

Design, Modeling, and Execution in the Ceiba Field, Equatorial

Guinea. Paper SPE 95514 presented at the SPE Annual Technical Con-

ference and Exhibition, Dallas, Texas, 9–12 October. http://dx.doi.org/

10.2118/95514-MS.

Farias, R., Li, J., Vilela, A. et al. 2007. Openhole Horizontal Gravel Pack-

ing Offshore Brazil: Best Practices and Lessons Learned From 72

Operations. Paper SPE 107190 presented at the SPE Latin American

and Caribbean Petroleum Engineering Conference, Buenos Aires, Ar-

gentina, 15–18 April. http://dx.doi.org/10.2118/107190-MS.

Gillespie, G., Angel, K., Cameron, J. et al. 2005. Troika Field: A Well

Failure, and Then a Successful Workover. Paper SPE 97291 presented

at the SPE Annual Technical Conference and Exhibition, Dallas,

Texas, 9–12 October. http://dx.doi.org/10.2118/97291-MS.

Hale, C., Conrad, M., Bose, M. et al. 2004. Is Live Annulus Data Interpre-

tation During Frac-Pack Operations Viable Information? Paper SPE

86461 presented at the SPE International Symposium and Exhibition

on Formation Damage Control, Lafayette, Louisiana, 18–20 February.

http://dx.doi.org/10.2118/86461-MS.

Hannah, R.R., Park, E.I., Porter, D.A. et al. 1994. Combination Fractur-

ing/Gravel-Packing Completion Technique on the Amberjack, Missis-

sippi Canyon 109 Field. SPE Prod & Fac 9 (4): 262–266. http://

dx.doi.org/10.2118/26562-PA.

Hern, G. 2010. Deepwater Wellbore Cleanup System. Paper SPE 137090

presented at the SPE Deepwater Drilling and Completions Conference,

Galveston, Texas, 5–6 October. http://dx.doi.org/10.2118/137090-MS.

Holcomb, W.D., Landry, T.J., Comeaux, B.A. et al. 2002. New Technique

Restores Initial Fluid Efficiency Observed in Mini-Frac and Results in

Increased TSO Frac-Pack Success. Paper SPE 77775 presented at the

SPE Annual Technical Conference and Exhibition, San Antonio,

Texas, 29 September–2 October. http://dx.doi.org/10.2118/77775-MS.


Javora, P.H., Stevens, R., Devine, C. et al. 2006. Deepwater Completion

Challenges Re-Define Best Practices for Completion and Packer Fluid

Selection. Paper SPE 103209 presented at the SPE Annual Technical

Conference and Exhibition, San Antonio, Texas, 24–27 September.

http://dx.doi.org/10.2118/103209-MS.

Joseph, K.P. 2010. Case History: First of Its Kind: Installation of the Mul-

tizone Single-Trip (MST) Technology in Deep Water, India. Paper

SPE 134084 presented at the SPE Annual Technical Conference and

Exhibition, Florence, Italy, 19–22 September. http://dx.doi,org/10.2118/

134084-MS.

Liu, L., Deng, J., Ma, Y. et al. 2006. Single-Trip, Multiple-Zone Frac

Packing Offshore Sand Control: Overview of 58 Case Histories. Paper

SPE 103779 presented at the International Oil and Gas Conference and

Exhibition in China, Beijing, China, 5–7 December. http://dx.doi.org/

10.2118/103779-MS.

Malochee, S. and Comeaux, B. 2003. Case Study: Analyzing Bottomhole

Temperature Gauge Data in Gulf of Mexico Frac Packs to Optimize

Fracture Fluid Crosslink, Stability, and Break Times. Paper SPE 84215

presented at the SPE Annual Technical Conference and Exhibition,

Denver, Colorado, 5–8 October. http://dx.doi.org/10.2118/84215-MS.

McLarty, J.M. and DeBonis, V. 1995. Gulf Coast Section SPE Production

Operations Study Group—Technical Highlights from a Series of Frac-

Pack Treatment Symposiums. Paper SPE 30471 presented at the SPE

Annual Technical Conference and Exhibition, Dallas, Texas, 22–25

October. http://dx.doi.org/10.2118/30471-MS.

Moreno, B., Haydell, G., and Landry, L. 2009. Critical Data Needs for

Design of Frac-Pack Completions in Today’s Oilfield Environment.

Paper SPE 124389 presented at the Offshore Europe Meeting, Aber-

deen, UK, 8–11 September. http://dx.doi.org/10.2118/124389-MS.

Neumann, L.F., Pedroso, C.A., Moreira, L. et al. 2002. Lessons Learned

from a Hundred Frac Packs in the Campos Basin. Paper SPE 73722

presented at the SPE International Symposium and Exhibition on For-

mation Damage Control, Lafayette, Louisiana, 20–21 February. http://

dx.doi.org/10.2118/73722-MS.

Norman, D. 2004. Frac-Pack Completion: “Why Has It Become the Stand-

ard Strategy for Sand Control?”. Paper SPE 101511-DL presented at

the SPE Distinguished Lecture 2003–2004.

Ogier, K.S., Haddad, Z., Moreira, O. et al. 2011. The World’s Deepest

Frac-Pack Completions Utilizing a Single-Trip, Multi-Zone System: A

Gulf of Mexico Case Study in the Lower Tertiary Formation. Paper

SPE 147313 presented at the SPE Annual Technical Conference and

Exhibition, Denver, Colorado, 30 October–2 November. http://

dx.doi.org/10.2118/147313-MS.

Ott, W. and Woods, J. 2003. Modern Sandface Completion PracticesHandbook. World Oil Magazine. Houston, Texas: Gulf Publishing

Company.

Petit, G., Leschi, P., and Dusterhoft, R. 1995. Frac and Pack Stimulation:

Application and Field Experience From Hylia Gabon, West Africa. Pa-

per SPE 30115 presented at the SPE European Formation Damage

Conference, The Hague, The Netherlands, 15–16 May. http://

dx.doi.org/10.2118/30115-MS.

Pourciau, R.D. 2007. Deepwater Extended-Reach Sand-Control Comple-

tions and Interventions. SPE Drill & Compl 22 (2): 157–164. http://

dx.doi.org/10.2118/98563-PA.

Pourciau, R.D., Fisk, J.H., Descant, F.J. et al. 2005. Completion and Well-

Performance Results, Genesis Field, Deepwater Gulf of Mexico. SPEDrill & Compl 20 (2): 147–156. http://dx.doi.org/10.2118/84415-PA.

Rovina, P.S., Pedroso, C.E., Coutinho, A.B. et al. 2000. Triple Frac-Pack-

ing in an Ultra-deepwater Subsea Well in Roncador Field, Campos Ba-

sin—Maximizing the Production Rate. Paper SPE 63110 presented at

the SPE Annual Technical Conference and Exhibition, Dallas, Texas,

1–4 October. http://dx.doi.org/10.2118/63110-MS.

Sanford, J., Bruton, J., Woomer, J. et al. 2010. Quantitative Frac-Pack

Analysis Using Dual Tracer Logs and Downhole Gauges. Paper SPE

137757 presented at the SPE Deepwater Drilling and Completions

Conference, Galveston, Texas, 5–6 October. http://dx.doi.org/10.2118/

137757-MS.

Smith, J., Vitthal, S., McGowen, J.M. et al. 2000. How Minifracs Alter

Leakoff and Ways to Counteract It. Paper SPE 58767 presented at the

SPE International Symposium on Formation Damage Control, Lafay-

ette, Louisiana, 23–24 February. http://dx.doi.org/10.2118/58767-MS.

Smith, J.E., Meyer, B.R., and Jacot, R.H. 2002. Fracture Pressure-Slope

Analysis for TSOs in High-Permeability Formations. SPE Prod & Fac17 (2): 110–121. http://dx.doi.org/10.2118/78149-PA.

Stewart, B.R., Mullen, M.E., Ellis, R.C. et al. 1995. Economic Justification

for Fracturing Moderate to High-Permeability Formations in Sand

Control Environments. Paper SPE 30470 presented at the SPE Annual

Technical Conference and Exhibition, Dallas, Texas, 22–25 October.


Suryanada, S., Wahyudhi, F., Garcia, E. et al. 2010. Saving 70% Rig Com-

pletion Time on 13 Multizone Wells With Single-Trip Multizone

Completion System in Mahakam Delta Offshore Indonesia. Paper SPE

133409 presented at the SPE Annual Technical Conference and Exhi-

bition, Florence, Italy, 19–22 September. http://dx.doi.org/10.2118/

133409-MS.

Tiner, R.L., Ely, J.W., and Schraufnagel, R. 1996. Frac Packs—State of

the Art. Paper SPE 36456 presented at the SPE Annual Technical Con-

ference and Exhibition, Denver, Colorado, 6–9 October. http://

dx.doi.org/10.2118/36456-MS.

Van Sickle, E., Womble, A., and McKown, M. 2006. Achieving Savings

in Time-Sensitive Completion Costs: Results from Single-Trip Multi-

zone Frac-Packing Case Histories. Paper SPE 103184 presented at the

SPE Annual Technical Conference and Exhibition, San Antonio,

Texas, 24–27 September. http://dx.doi.org/10.2118/103184-MS.

Vincent, M.C., Pearson, C.M., and Kullman, J. 1999. Non-Darcy and Mul-

tiphase Flow in Propped Fractures: Case Studies Illustrate the Dra-

matic Effect on Well Productivity. Paper SPE 54630 presented at the

SPE Western Regional Meeting, Anchorage, Alaska, 26–27 May.


Vitthal, S. 2003. A Review of Deepwater Completions—Case Histories

Selection and Emerging Technologies. Paper presented at the Deep-

water Technology Conference, Kuala Lumpur, Malaysia, 14–17 July.

Jeff Li has worked in the coiled-tubing (CT) service industrysince 1996. He has been directly involved in the research anddevelopment of several CT technologies, ranging from CT dril-ling, milling, fracturing, and sand cleanout. Currently, Li is theprincipal investigator for the project of the mud displacementin the primary cement and the cement-sheath failure evalua-tion. His particular expertise is with multiphase-fluid flow andsolids-transport studies in sand cleaning, gravel packing, dril-ling, and cementing process. Li holds BSc and MSc degreesfrom Xian Jiaotong University, China. He also holds MSc andPhD degrees in mechanical engineering from the University ofSaskatchewan, Canada. Li has published more than 30 tech-nical papers, has held several patents, and is a technicalreviewer for SPE Drilling and Completion. He is a member ofSPE and ICoTA.

John Weirich is current Senior Manager of the Lower Comple-tions and Reservoir Applications Engineering Group for BakerHughes in Houston, Texas. He has more than 30 years of world-wide operational, marketing, and technical experience insand control and lower completions.

Tarik Abdelfattah has been working with Baker Hughes forapproximately 4 years, focusing mainly on lower completionsand applications related to production optimization. Withinthe Lower Completions and Reservoir Applications Team, he isresponsible for providing technical assistance and recommen-dations on sand-control methods and inflow-control comple-tions. Abdelfattah’s primary focus is simulating added benefitsresulting from running such completions with petroleum engi-neering fundamentals and integrated modeling. He earned aBS degree in petroleum engineering from Texas A&M

SI Metric Conversion Factors

bbl � 159 Eþ00 ¼ L

ft � 0.3048* Eþ00 ¼ m

in. � 25.4* E�03 ¼ m

psi � 6.895 Eþ03 ¼ Pa

*Conversion factor is exact.


University, and during his tenure with Baker Hughes, he haspublished two SPE papers pertaining to the work he has beeninvolved with in the group.

Carlos Alberto Pedroso became a chemical engineer in 1986and a petroleum engineer in 1987, when he joined Petrobras.He worked in Reconcavo basin (onshore northeastern Brazil)until 1995, when he started a master’s degree in petroleum en-gineering at Campinas University for hydraulic fracturing. In1997, Pedroso joined the Campos Basin Stimulation Team, andsince then has focused his efforts to develop sand-control andstimulation (SC&S) solutions for deepwater environments. In

2003, he became a technique adviser for SC&S. In 2006,Pedroso was an SPE Distinguished Lecturer, discussing fracpacks in ultradeep water. In 2009, he was recognized with thenational prize, the 2009 Petroleum and Gas Brazilian NationalIndustry Personality: Technique Excellence. In 2010, Pedrosowas recognized with the 2010 SPE South American and Carib-bean Production and Operations Award. Currently, he is theManager for SC&S for all offshore Brazil operations. Pedroso isthe Chairperson of the SPE Macae Section. Author of morethan 20 SPE papers (and 43 Petrobras papers), he has made asubstantial contribution to SC&S development, introducing orcreating new technologies.


spe-147419-pa-psdfsdfd

Documents

fracpacking treatments

key fracpacking parameters

fracpack completion

different fracpacking

petrobrassummaryfrac

improved packing efficiencyand

high fluidleakoff rates

high permeability