By Deane Sparkman,Jamel Belhadiand George Waters

HOUSTON–The technique of usingmicroseismic monitoring of hydraulicfracturing jobs has proven to be an effectiveway to see if the fractures propagate ac-cording to plan. By mapping the hydraulicfractures, operators have been able toidentify untreated reservoir sections thatcan be targeted on subsequent treatments,as well as see whether a fracture intersectsan aquifer or other geohazard, or perhapsanother well.Typically, an array of geophones is

deployed in a nearby offset well. Initially,vertical wells were chosen, largely outof convenience. There were often manynearby vertical wells to choose from, anddeploying on wireline was efficient andcost effective. However, after gaining ex-perience in microseismic monitoring,many operators are deploying the seismicarrays in horizontal wells to take maximumadvantage of the rich data sets that canbe acquired. Pump-down techniques ordownhole tractors are used to place theseismic monitoring equipment preciselyin the horizontal observation wells.Recently, powerful computers have

been able to process the acquired micro-seismic data in real time, using a techniquecalled StimMAP™ Live, which providesfracture mapping within 30 seconds ofmicroseismic activity. Based on proprietarycoalescence microseismic mapping(CMM) technology that enables fast andaccurate processing of events, this diag-nostic service provides a propagationmap after each stage of a multistage fracjob. This allows engineers to make decisions“on the fly” as the job progresses to improvefracture quality and reservoir contact.

Some of the changes operators haveimplemented on site as a treatment pro-ceeds include the ability to alter the lo-cations of perforations for the next stage,changing the shot density or perforationintervals, and changing the pumpingschedule. These have added significantlyto the value of the frac job. Several new techniques have been en-

hanced by microseismic monitoring. Oneexample is “‘zipper-frac,” a techniquethat involves alternating stages from twoor three adjacent wells while holdingpressure on the previously fractured well.This creates a complementary stress fieldaround the well just stimulated, which

prevents the fractures from the well thatis being stimulated from intersectingthose from the previous well. The resultis thorough reservoir contact with no in-terwell contamination.

‘Steering’ FracturesThe industry is still learning all the

benefits that can be obtained from real-time microseismic monitoring of hydraulicfractures. One of the most recent benefitsis a combination with diversion technologyto “steer” the fractures to contact specificreservoir volumes. With this ability, com-panies have been able to produce numer-ous, closely spaced fractures instead of a

Real-Time Monitoring ‘Steers’ Fractures

FIGURE 1Seismic Map of Barnett Completions with Microseismic Monitor Well

SOURCE: All images courtesy of Devon Energy.

The “Better Business” Publication Serving the Exploration / Drilling / Production Industry

DECEMBER 2009

Reproduced for Schlumberger with permission from The American Oil & Gas Reporter

few deep, widely spaced fractures.Studies have shown that when frac

stages are spaced at great intervals, reservoirdrainage is relatively poor. But when frac-tures are more closely spaced, the reservoirrecovery factor is dramatically improved.For example, in a 400 nanoDarcy shalereservoir with fracture stages spaced at1,000 feet, the recovery factor is only about50 percent after 60 years of continuousproduction. If the same reservoir was frac-

tured with 250-foot spacing, it would bealmost completely depleted after 60 years.Moreover, the 250-foot spaced fractureswould drain about the same amount of gasin 10 years as the 1,000-foot spaced fracturescould drain in 60 years.Multistage fracturing technology allows

stages to be closely spaced, but gettingall the fractures to accept fluid has beenproblematic. The fluid always followsthe path of least resistance, and once it

opens up a fracture, it tends to follow ituntil screen-out. However, new degradablediversion media have allowed engineersto shift away from early fractures andopen new ones, giving much better overallreservoir contact. After a few days, thediversion material in the early fracturesdissolves and all the fractures are leftopen to produce.This is where the real-time microseismic

monitoring comes in. When engineers seea fracture developing, it can be observed,and propagation arrested after the fracturereaches optimum length by adding thedegradable diversion media to the slurry.This will bridge the fracture and cause thenext path of least resistance to open. Usinga succession of diversion stages, the fracturescan be steered to intersect the maximumamount of reservoir rock. All of the fracturescreated during one treatment stage aremapped using the microseismic monitoringtechnique, and the collective data are usedto optimize the next stage until all stageshave been pumped.The degradable diversion media con-

sists of millions of tiny fibers. In additionto helping bridge off a fracture and di-verting pumping energy to another spot,the fibers also prevent proppant from“slumping” to the bottom of the fracture,thereby ensuring uniform proppant dis-tribution across the entire fracture height.

Barnett Shale Case Study

Stretching across North-Central Texas,the Barnett Shale has benefited greatlyfrom microseismic fracture monitoring.The shale play is tight with gas-filled

FIGURE 2Section View of First-Stage Treatment

FIGURE 3Plan and Section Views of All Treatment and Diversion Stages

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porosities from 3 to 5 percent and per-meability on the order of nanoDarcies.Lying just beneath the Barnett to thewest is the Ellenberger carbonate, aporous, karsted limestone that is waterbearing. Most of the Barnett Shale is un-derlain by the Viola Limestone, whichprovides a hydraulic seal between thedeeper Ellenberger and the Barnett, butthe Viola pinches out to the west of FortWorth. As a result, for many of thewestern Barnett wells, there is a dangerthat hydraulic fractures will propagateinto the Ellenberger and flood out.Devon Energy Corporation faced the

possibility of unwanted Ellenberger waterin some of its Barnett Shale wells. Thesituation is illustrated in Figure 1, whichshows a seismic map of Barnett comple-tions with the microseismic monitor well(closure stress gradients are indicated bycolored “flashing,” with red denotinghigh stress). Two horizontal producers,one drilled from north to south and theother drilled from west to east, bracketeda fault of the Ellenberger, labeled as ageohazard on the map. A horizontal ob-servation well lay between the two pro-ducers. Engineers wanted to carefullyobserve the first-stage treatment of thewest-to-east producer to ensure they didnot frac down into the Ellenberger.After an array of geophones was de-

ployed in the observation well, treatmentbegan using the “plug n’ perf” technique,which has enjoyed a renaissance in pop-ularity since the advent of microseismic

monitoring because the technique allowsengineers to make frac design changesbased on observations of each stage inthe multistage treatment. Figure 2 showsa section view of the stage-one treatment.

The yellow bubbles represent the micro-seisms recorded during stage one, andclearly show that the fracture did notpropagate into the geohazard.As subsequent stages were treated, di-

FIGURE 4Restimulation Candidate Well (Original Microseismic Map and

Locations of Original and Proposed Perforations)

Distance South-North (ft)

2,400

2,000

1,600

1,200

800

400

0

-400

-800-2,800 -2,400 -2,000 -1,600 -1,200 -800 -400 0 400

00

Distance East-West (ft)

ToeMonitor Well

Heel

Original Perfs

Refrac Perfs

FIGURE 5Restimulation Map (New Fractures Created Toward Heel of Well During Second-Stage Diversion)

Distance South-North (ft)

2,400

2,000

1,600

1,200

800

400

0

-400

-800

-2,800

-2,000

-2,400

-1,600

-1,200

-800

-400 0

400

0 0

Distance West-East (ft)

Original Microseismic Activity

Stage 1 Refrac Microseismic Activity

Stage 2 Refrac Microseismic Activity

Monitor Well

Num

ber of Microseismic Events

600

500

400

300

200

100

0

10,000

9,2009,0008,8008,6008,4008,200

9,400

8,000

9,600

9,800

7,8007,600

Distance Along Well Bore MD (ft)

Stage 1

Stage 2

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verters were employed to shift the fracturesinto untreated volumes of the reservoir.Figure 3 shows both plan and sectionviews of all treatment and diversionstages, with bubbles color coded to indicatethe effect of the diversion media. The re-sults show a wide dispersal of fractures,with the propagation of all subsequentfracturing staying well away from thegeohazard.

Restimulation ProjectIn a second example, Devon planned

to re-enter a producing well and restimulateit. The plan was to perforate between thepreviously perforated zones to improvereservoir contact and open new volumesto production. Figure 4 shows the res-timulation candidate well with originalperforations (black) and the original mi-croseismic hydraulic fracture stimulationdiagnostics plot, as well as the proposedlocations of refrac perforations (orange). The original well was drilled in the

direction of minimum horizontal stressand cased with 5½-inch uncemented pipe.The well bore orientation favored thegeneration of transverse fractures, andthat is what occurred when the well wasinitially treated in a single-stage hydraulicfracturing job. Instantaneous shut-in pres-sure following treatment was 2,050 psi.After about 4½ years, the well was res-timulated using fiber diversion media todivert the retreatment from migratingalong the casing annulus and enteringthe original fractures.Using real-time microseismic monitoring

in conjunction with the fiber diverters, theengineers were able to make treatmentchanges on the fly to improve the overalleffectiveness of the stimulation. Devonwas able to open several new fractures bydeploying fracture diversion stages atstrategic intervals during treatment. Pumppressure showed that the diverters wereeffectively bridging off the old fracturesand creating new ones. The diverters weredeployed in four stages, with deploymenttimes guided by real-time observationsfrom microseismic monitoring.Figure 5 shows the result of the com-

pleted restimulation, color-coded to showthe effect of the different diversion stages.A histogram illustrates how substantialnew fractures were created closer to theheel of the well during the second-stagediversion.The restimulation job was enabled by

the effective use of fiber diversion mediato shift stimulation energy to new areasof the reservoir. Deciding when to deploy

the diverters was enabled by real-timemicroseismic monitoring. The combinationof the two techniques resulted in a 400percent improvement in production rateover the initial completion. The productionhistory in Figure 6 shows the results ofthe successful restimulation treatment.Payout for the restimulation job wasachieved in about 60 days.According to the operator’s estimates,

ultimate recovery from the well has beenboosted by 20 percent by the restimulationtreatment. The technique bodes well for

the more than 8,000 horizontal producingwells drilled in the Barnett to date, andshould work equally well in cementedcompletions, as well as in other shale playsworldwide. r

Editor’s Note: For more detailed in-formation on the microseismic monitoringwork performed in the Devon EnergyBarnett Shale wells, please see OTC20268, a technical paper presented at the2009 Offshore Technology Conference,held May 4-7 in Houston.

Production History (Restimulation Treatment)FIGURE 6

Normalized

Gas Rate

Norm

alized Cum

ulative Production

2,2500 750500250 1,000 1,250 1,500 1,750 2,000Production Time (Days)

DEANE SPARKMAN is a geophysi-cist at Devon Energy Corporation inOklahoma City. She has worked theBarnett Shale in the Fort Worth Basinfor Devon Energy since 2005. Her workhas focused on integrating seismic, seis-mic attributes, microseismic and pro-duction to optimize completion tech-niques in unconventional reservoirs.Sparkman holds a B.S. in geology andan M.S. in geophysics from the Universityof Oklahoma.

JAMEL BELHADI is an operationsengineering adviser working for DevonEnergy Corporation in Oklahoma City.His 25 years of oil field experiencecover reservoir characterization andmodeling, well placement and construc-tion, horizontal completions and stim-ulation, real-time microseismic moni-toring, production monitoring and op-timization, and workover operations.In his current position, Belhadi is re-sponsible for completion and production

engineering operations in the BarnettShale play. He holds an M.S. from theUniversity of Southern California.

GEORGE WATERS is the North Amer-ican reservoir stimulation domain man-ager for Schlumberger in Oklahoma City.He is responsible for developing and di-recting the technical strategy for theSchlumberger stimulation business inNorth America. Waters is a 2009-10 So-ciety of Petroleum Engineers’ distinguishedlecturer on stimulating shale reservoirs.He joined Schlumberger in 1985 andhas held numerous completion engineeringassignments, focusing primarily on low-permeability hydraulic fracture optimiza-tion. Since 2000, he has concentrated onevaluating and completing shale reser-voirs. Waters holds a B.S. in petroleumengineering from West Virginia University,an M.S. in environmental engineeringfrom Oklahoma State University, and anM.S. in petroleum engineering from theInstitut Francais du Petrole.

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