Copyright 1999, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE European Formation DamageConference held in The Hague, The Netherlands, 31 May–1 June 1999.

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AbstractThis paper presents results related to the use of the ball sealerdiversion technique to fracture long and multiple Triassic sandintervals in the Alwyn Field. It also focuses on themethodology adopted to design and prepare the treatment.This technique was applied on a well producing from a grosspay zone thickness of 350 m with a perforated length of 98meters. The production decreased drastically after condensatedeposition in all reservoir intervals induced high skin levels.Due to low permeability, matrix treatments were discarded asa solution. Instead, a proppant fracture treatment was plannedto by-pass the skin, using ball sealer diversion to treat theentire perforated interval.

The treatment was performed successfully in several stagesincluding gel pad, proppant and ball sealers. Good indicationsof diversion showed that most of the intervals were fractured.However, performing such a treatment requires sophisticatedengineering to determine the optimum number of stages,number of ball sealers per stage, gel and proppant volumes perstage and pumping rate.The success of this operation will allow the technique to beconsidered for wider application such as fracturing longintervals in deviated or horizontal perforated wells at moderatecost.

IntroductionThe Alwyn North Triassic gas condensate field, discovered in1992, is located approximately 250 km north east of theShetland Islands. Several wells have been drilled throughmultilayered gas bearing sands, which spread over 800 mdepth, at approximately 3600 m TVD and gave good initial

gas production. Unfortunately, the gas production of severalwells decreased rapidly due to formation damage resultingfrom condensate deposition in the reservoir, a phenomenonwhich is getting worse with time.

One well, the 3/9a-N34, which was producing 280,000m3/d of gas at the end of 1996, stopped producing entirely inMarch 1998 due to this phenomenon. A treatment was plannedto restore the initial productivity of the well. As permeabilitieswere low (0.1 to 2 md), a matrix treatment was discarded anda hydraulic fracturing treatment was planned.

As the targeted gross pay zone was 350 m vertical heightwith 98 m of perforations, several fracture treatments usingpackers or sand plugs for isolation would be required.Alternatively, a diversion technique, which placed proppant inall 19 different layers of the reservoir, could be used.

The use of packers or sand plugs was deemed too risky andexpensive, so ball sealers were chosen for diversion. Severalpad / proppant / ball sealer stages were planned. Even thoughthe methodology required to optimize the use of ball sealers iswell known in matrix treatments, it was necessary in this caseto work on a methodology adapted to a hydraulic fracturingtreatment.

This paper describes the methodology used for the designof a hydraulic fracturing treatment in long and multipleTriassic sand intervals, using ball sealers for diversion.Recommendations are given for the determination of theoptimum number of stages, number of ball sealers per stage,gel and proppant volumes per stage and pumping rate. Finally,details are given of the sequence of operations and an analysisof the main frac is made in the light of post frac productiondata.

Field DescriptionThe Alwyn North Field is situated in Blocks 3/9a and 3/4a inthe region located approximately 250 km north east of theShetland Islands as shown in Fig. 1. The Alwyn North Triassicgas condensate reservoir was discovered by means of the3/10b-2 well in 1992, and confirmed with wells N33, N34,N35 & N38 from 1995 to 1998. These appraisal wellsencountered interbedded gas-bearing sands (approximately800 m thickness) at approximately 3600 m vertical depth. Theinitial reservoir pressure was 8410 psi. The permeabilityranges from 0.1 to 10 md and decreases with depth. As a

SPE 54740

Ball Sealer Diversion When Fracturing Long and Multiple Triassic Sand Intervals onAlwyn Field, North SeaPascal Baylocq, Jean Jacques Fery, Laurent Parra, Total, Emmanuel Derbez, Halliburton

2 P.BAYLOCQ, J.J.FERY, L.PARRA, E.DERBEZ SPE 54740

result, the gas recovery factor expected in the lower zones ofthe reservoir is only 24%. Therefore, hydraulic fracturing hasbeen investigated and tested successfully (on well N38) for thedevelopment of the field.

Well DescriptionWell 3/9a-N34 is a triassic gas well drilled in 1996 through amultilayered reservoir consisting of 10 main zones: A, B1, B2,B3, C1, C2, D1, D2, D3 and D4. Each zone is divided intoseveral layers (a, b, c, d…) as shown on the reservoir log (Fig.2). The average reservoir characteristics are:

Average initial pressure: 8410 psiDew point pressure: 7163 psiPresent average bottom-hole static pressure: 7120 psiAverage reservoir temperature: 135°CPermeability: 0.1 to 2 mdAverage measured depth: 4250 to 5050 m BRTAverage vertical depth: 3750 to 4550 m TVD

The well is perforated in 19 layers (see the reservoir log in fig.2and the completion schematic in Fig. 3) with 2-3/4” guns (6spf, 60° phasing, average penetration of 15.08”, average holediameter of 0.266”).

The completion is standard 5”, 20.3 lb/ft L80 tubing in a7”, 32 lb/ft, P110 liner as shown in fig.3. The well is S shaped,with a maximum inclination of 33° at 1271 m BRT and 0°inclination through the reservoir section.

One peculiarity of the well is the presence of 2 permanentpackers in the 7” liner (equipped with tail pipe, nipple andwireline entry guide) which were used during selective testoperations.

For production purposes, the bottom perforations (C2 &D2 layers) were isolated with a plug in the lowest 3.658”nipple. It has to be noted that the total gross height of theproducing interval is approximately 350 m TVD with a totalperforated height of 98 m TVD.

Production History and Diagnosis of the DamageThe 3/9a-N34 well was drilled in 1996 and completed inOctober of that year. The initial production was 280,000 m3/dof gas, 820 bpd of condensate at 1087 psi WHP. In May 1997,the production had decreased to 188,000 m3/d of gas at 1015psi WHP. As formation damage was suspected, a PLT was runin order to analyze, localize and quantify the damage. Adetailed analysis of the log showed that nearly all of the layershad a positive skin ranging from 1 to 40, some layers beingcompletely plugged. Results per layer (kh, skin, gas rate) aresummarized in Table 1.

After investigation, it appeared that the main cause of thedamage was condensate deposition in the reservoir. This wasthe result of production below the dew point. This damageresulted in pressure losses near the wellbore and reduced thebottom-hole flowing pressure. As a result, more condensatedeposition took place. Therefore, this phenomenon is self-perpetuating and will continue until the well dies.

As a result of the damage, the production decreased to 85,000m3/d of gas, 257.9 bpd of condensate at 986 psi WHP inNovember 1997. The well finally died in March 1998 with awellhead shut-in pressure of 391 psi.

Choice of TreatmentIn order to remove the damage, several types of treatmentswere investigated:• Matrix acidizing: initially the plan was to stimulate the

near-wellbore area in order to increase the bottom-holeflowing pressure and to decrease the condensatedeposition phenomenon. This idea was discarded becausethe average permeability of the reservoir was too low.Additionally, it would have been very difficult to getsufficient injectivity to perform the treatment.

• Hydraulic fracturing1: the idea was to by-pass the damagein the different layers with a short but highly conductivefracture. However, due to the height of the reservoir (totalproducing interval of 350 m TVD, 98 m TVD ofperforations) it was not possible to perform the treatmentin one sequence. It was therefore necessary to conductseveral fracturing jobs (3 to 4) using retrievable bridgeplugs or sand plugs to isolate the different fractures,which would have involved several coiled tubingoperations. An estimation of the feasibility, the risk andthe cost of such an operation rapidly dispelled this idea.

• Hydraulic fracturing with ball sealers: the objective ofsuch a treatment was to fracture all of the producinglayers in one operation. It was necessary to find adiversion method that could be utilised in one operation,that would fracture all of the layers. Ball sealer diversiontechnique was selected based upon the ease of operations,low cost and low risk.

Design of the TreatmentThe objective and the general characteristics of the treatmentwill be reviewed, (fluid formulation, proppant type, ball sealerselection) after which the design of the frac job will bepresented including the stages, volumes, rate, ball sealersequence, etc.

Objective of the TreatmentThe objectives of the treatment were to:• perform a hydraulic fracturing treatment to by-pass the

damage present in the different layers• fracture as many layers as possible in one treatment: 16

layers with a total interval gross height of 350 m TVDwith 98 m TVD of perforations

• use ball sealers for diversion in order to place proppant inthe different layers

Surface FacilitiesOne critical part of the job preparation was the study of theclean-up of the well once the frac job was completed. In theNorth Sea environment, where no oil sheen on the sea surfaceis tolerated, it was a concern to dispose of the oily proppant

SPE 54740 BALL SEALER DIVERSION WHEN FRACTURING LONG AND MULTIPLE TRIASSIC SAND INTERVALS 3ON ALWYN FIELD, NORTH SEA

mixed with water based gel. It was therefore decided toconduct the clean up through the production facility and toavoid the use of the burner booms as much as possible.

A detailed schematic of the temporary testing kit (testingmanifold, sand filters, burner boom, diverters) is given in Fig.10. In case of screen out, a coil tubing intervention through thecompletion tubing was planned to circulate out the remainingproppant and to initiate flow back.

General characteristics of the treatmentFluid formulation A delay-crosslinked borate-based fluid

system was utilised. A temperature simulation was conductedso that the fluid that was pumped could be optimized for bothviscosity stability and breaking rate at the temperatures thefluid would encounter in the fracture during and after thetreatment.

Due to multiple small stages of fluid that were to bepumped, it was assumed that each stage of crosslinked fluidpumped into this well would follow a rapid heat up, similar tothe heat up that would be observed at the tip of a fracture.

The requirement for the apparent viscosity of the fluid wasto be over 100 cp at 80 sec–1 for at least 1 hour with a rapidheat up rate to 135 °C. At this temperature, a high pH level(pH-initial equal to 12) and a high polymer loading werenecessary. A 50 lbs/Mgals guar system with a minimumnumber of additives was chosen (see Table 2).

To break the fluid at an acceptable rate, a high-temperaturebreaker aid was proposed with an initial concentration of 0.05gal/Mgals in the first stage, increasing to 0.1 gal/Mgals in thelatter stages (see Table 3).

Induced emulsion break tests were also conducted withbroken guar-based fluid and a sample of crude oil from thewell. No emulsion was observed.

Proppant type The proppant type was chosen based on themaximum in-situ stress of the formation (estimated at 0,8psi/ft) and the temperature. The possible choices wereIntermediate Strength Proppant or Bauxite. Due to its higherconductivity, 20/40 Bauxite was selected. As proppantflowback was not expected, the choice of a resin coatedproppant was discarded.

Ball sealer selection The selection of the ball sealersdepended on the following parameters:

- perforation diameters- bottom-hole temperature- differential pressure across the perforations- flow rate through the perforations- density contrast between the fluid and the ball

The perforation diameter ranged between 0.222 inches and0.309 inches. Therefore, 5/8 inch balls were selected. Due tothe bottom-hole temperature, Rubber Coated Nylon balls wereselected. The ball density was selected to be as high aspossible (1.3 S.G.) to reduce the probability of ball flow-back.

Hydraulic Fracturing Design & ProgramMinifrac 6000 gallons of crosslinked gel were pumped at 20bpm for the minifrac. The objective was to determine thefracture pressure, the leak-off coefficient and to detect anytortuosity effects. Downhole pressure gauges were run abovethe top perforations in order to perform an accurate analysis ofthe bottom-hole pressure.

Temperature log A temperature log was run in order todetermine within which layer the fracture initiated and whatthe fracture height was.

Main frac As the objective of the main frac was to createseveral fractures, the following sequence was pumped:

a) - padb) - proppant rampc) - ball sealers to create diversiond) - Repeat the above several times

To do this, it was necessary to optimize two importantparameters: the number of pad / proppant / ball sealer stagesand the number of ball sealers to pump in each stage.

Sequence of pad/proppant / ball sealers stagesTo determine the number of stages, the minimum and majorhorizontal stresses were calculated in each layer, taking intoaccount the pore pressure of each layer. These calculationswere based on rock mechanic studies from which theminimum and major horizontal stresses were derived. Resultsare summarized in Table 4. It appeared that the maximumMinor Stress was lower than the minimum Major Stress sothat there was little risk of reinitiating a fracture in an intervalthat had already been fractured.

Looking at the Minimum Stress differences betweenlayers, layer heights, reservoir pressures, gas rates andpermeabilities, it was concluded that 7 main fractures couldresult from the diversion, in the following order:

• initially in the B1a• then in B2a• B2c• B3a• B3b• C1a• and finally C1bcdef

As a consequence, it was decided to pump 7pad/proppant/ball-sealer stages. Volumes and rates aredetailed further on in the paper.

Ball sealers number and sequenceSeveral techniques2,3 exist to design ball sealer treatments.However, they are usually applied for matrix treatments andnot fracturing treatments.

Therefore, optimizations of the number of ball sealers weremade on the following assumption: when the fracture is

4 P.BAYLOCQ, J.J.FERY, L.PARRA, E.DERBEZ SPE 54740

opened, most of the fluid flows through the perforations thatare in contact with the fracture. This means that it is notnecessary to seal all of the perforations to create gooddiversion. Sealing only the perforations that are in contact withthe fracture is sufficient.

The question now is, how many perforations are in contactwith the fracture? With a phasing of 60°, two cases arepossible as shown in Fig. 4. In theory, 2 perforations out of 6are in contact with the fracture (mini case). However,depending on the azimuth of the fracture, 4 perforations out of6 could be in contact with the fracture (max case).

As a consequence, the assumption was made that onaverage, 3 perforations out of 6 would be in contact with thefracture. Thus, for a layer containing n perforations, we wouldpump n/2 ball sealers for diversion.

Main Frac Final DesignBased on the previous considerations, a design was made asshown in Table 5.It is important to stress a few important points:• Except for the first volume of pad, which was enlarged to

reduce the risks of early screen out, the volumes of padwere increased in every other stage. Because the sealingof the perforations by the ball sealers would probably notbe complete, the total leak off (through fractured areasand ‘unsealed’ perforations) would increase during thetreatment. As a consequence, it was decided to pumplarge pad volumes and to increase the pad volumes witheach subsequent stage.

• Ball sealers were pumped at the very end of the proppantramp (last 1000 gals), in order to have the maximumconductivity near the wellbore in all of the perforations.

• The volume and the maximum proppant concentration ofthe last ramp were larger than those of the previous ones.Indeed, as the perforations would probably not be sealedoff completely by the ball sealers, there was a risk ofoverdisplacing the proppant with the pad of eachfollowing stage. Thereby, losing the near wellboreconductivity. As a consequence, it was decided to pump alarge volume of proppant in the last stage (with a higherconcentration of 7 ppg) in order to place some proppant inall of the perforations and to maintain connectivity withthe fracture.

• Part of the displacement was made with diesel to facilitatethe kick off and the clean up of the well.

Performing the treatmentA dynamic positioning stimulation vessel was used to performthe treatment. A coflexip hose with a pressure rating of 10,000psi and one 4 inch line was rigged up from the boat to the frachead.

Operations sequenceMinifrac Before starting the minifrac, bottom-hole pressureand temperature gauges were run by wireline to 4282 m BRT

into the 7 inch liner, between the wireline entry guide and thetop perforations.

6000 gallons of seawater followed by 4000 gallons of freshwater with 2% KCl were pumped to fill up the well. Theformation broke down as the gas was squeezed into theformation. Then 6000 gallons of a 50 lbs/Mgals boratecrosslinked gel was pumped and displaced to the perforationswith linear gel at 20 bpm.

Formation breakdown occurred with a bottom-holepressure of approximately 9000 psi. During the injection test,which was done at a rate of up to 20 bpm, the bottom-holepressure increased from 9000 psi to approximately 9720 psi.Due to good indications of confinement of the fractureobtained during the minifrac, it was believed that only theupper B1a layer was fractured. (See Fig. 5)

Just before shut in, the bottom-hole pressure gaugeindicated 9720 psi. The ISIP was found to be approximately9510 psi, indicating a limited amount of near-wellbore friction(210 psi).

The pressure decline analysis showed a closure of 0.67psi/ft (8525 psi, see Fig. 6) which is in agreement with theminor stress calculated for the B1a interval (see table 4). Fromthis minifrac, the lowest minor stress of this multi-layerformation was determined. The fluid efficiency was found tobe 56%.

Temperature log A temperature log survey was performed4 hours after the minifrac, when the bottom-hole temperaturestabilized at approximately 110°C. The temperature wasnearly constant in all of the perforated layers so that norelevant information could be obtained from the log (See Fig.7). This was due to the large volume of water that wassqueezed (before the minifrac) in the matrix through all of theperforations.

Main frac The main frac design consisted of seven stages.Each stage was split into a pad of 5000 to 6500 gallons and a5500 to 8000 gallon sand-laden stage with a proppant ramp of1 to 5 ppg (7 ppg in last stage).

To ensure the diverting balls would seal properly, the flowrate was maintained at 20 bpm. This is equivalent to 5-8gallons per minute per perforation assuming only one layer ata time was fractured. A total of 144,000 lbs of proppant wasinjected into the formation. The maximum proppantconcentration was 7.2 ppg. Approximately 92,500 gallons of50 lbs/Mgals crosslinked gel was pumped at 20 bpm.

Quality control tests performed during the treatmentshowed good gel characteristics. The injection of the ballsealers was performed without any problems. A total of 479balls were injected. Balls were injected at the end of eachproppant stage.

Several rapid bottom-hole pressure changes indicated gooddiversion. An analysis of the bottom-hole pressure indicatedfracturing of 5 layers. This was confirmed by the tendency ofthe bottom-hole pressure to increase during the treatment (seeFig. 8).

SPE 54740 BALL SEALER DIVERSION WHEN FRACTURING LONG AND MULTIPLE TRIASSIC SAND INTERVALS 5ON ALWYN FIELD, NORTH SEA

Ball sealer injector Two ball injectors were used duringthis treatment. Balls were dropped one after the other asquickly as possible during the last 1000 gallons of each sandramp.

Treatment AnalysisBall sealers diversionThe main treatment analysis was conducted based oncalculated bottom-hole pressure. During the main treatment, asurface pressure increase was observed after each set of ballsreached the perforations. The calculated bottom-hole pressureincreased from 10,000 psi to 11,000 psi during the treatment.• First set of balls at perforations: As the first 60 balls hit

the perforations, the pressure at surface increased by 250psi, and the calculated bottom-hole pressure increased by500 psi. This indicates that the fluid was diverted to a newzone.

• Second set of balls at perforations: In this sequence, adiversion effect was observed as the balls sealed. Thebottom-hole pressure increased by 150 psi.

• Third set of balls at perforations: No diversion effect wasobserved when the balls hit the perforations.

• Fourth set of balls at perforations: In this sequence, a“local” screen-out may have taken place when the ballshit the perforations. The surface and bottom hole pressuresuddenly increased by 250 psi (See Fig. 9).

• Other stages at perforations: For each other set of ballsthat reached the perforations, a diversion effect wasobserved.

Main frac geometryUsing commercial fracture simulation software, the diversioneffect could not be modeled realistically. Thus, each fracturewas modeled based on the following assumptions:

First layer:- 100% of the pad went through one layer.- Only the considered layer was fractured.

Other layers:- Each pad was leaking partially (10-30 %) in the

previous fractured interval.- Only the considered layer was fractured.

Based on a pseudo 3D model, the average fracture length wasapproximately 150 ft. The average proppant height wasapproximately 100 ft for each layer, and the proppantconcentration was less than 1 lb/ft2.

Post frac production dataKick Off & Clean up. After the main frac, the well was shutin. It took approximately 4 hours for the gel to break(estimation done according to temperature heat up in thereservoir, and gel break time at 135°C). One important point isthat after the treatment, the wellhead pressure increased to

2972 psi (instead of 391 psi before the treatment) which meansthat some high-pressure layers were connected after the mainfrac. As a consequence, the well kicked off easily.

The cleanup was performed through the productionfacilities with the use of sand filters (see Fig 10). In order toavoid sand production, the well was cleaned up initially on asmall choke (16/64”) which was gradually increased by 4/64”every 6-8 hours. No flaring was performed. in accordance withNorth Sea environmental regulations.

Proppant flowback. At the beginning of the clean up, thewell produced approximately 2300 lbs of proppant (proppantleft in the wellbore after the shut in). Thereafter, no moreproppant was detected at surface, even after 4 months.

Post frac production test The hydraulic fracturing of N34appeared to be very successful with the following results:

• Pre-frac test : No production – well damaged.• Post-frac test : Qg = 352,000 m3/d – Qc = 983 bpd -

WHP = 986 psi on a 56/64”. These rates are initial rates(transient). After a few months, the gas rate stabilized atapproximately 250,000 m3/d (WHP = 1015 psi).

A PLT was performed in December 1998 and the detailedanalysis is given layer by layer in Table 6. From thecomparison between initial PI and post frac PI of each layer, itcan be inferred that most of the layers have been stimulatedsuccessfully. The average PI was increased by a factor of 7. Itis interesting to notice that most of the layers that were notproducing before the treatment have not been stimulated.

In view of these figures, the treatment paid for itself withinthe first 3 months, including rig time, wireline, pumpingoperations, chemicals, proppant, personnel and marinecharges, and continues to produce at a steady pace.

ConclusionsThe use of the ball sealers diversion technique to fracture longand multiple Triassic sand intervals has been testedsuccessfully and should be applied on damaged wells to by-pass the skin.

A sophisticated engineering technique is needed todetermine the optimum number of stages, number of ballsealers per stage, gel and proppant volumes per stage,pumping rate and design an efficient treatment. For thatpurpose, a methodology has been developed and adopted,producing highly successful results.

The success of this operation allows the technique to beconsidered for wider application such as for fracturing longintervals in deviated or horizontal perforated wells that haverecently been drilled or have been damaged over time. Insteadof performing several hydraulic fracturing operations usingsand plugs, packers or SSD, which result in high costs, thesame results could be obtained at low cost in one operationusing ball sealer diversions.

6 P.BAYLOCQ, J.J.FERY, L.PARRA, E.DERBEZ SPE 54740

AcknowledgementsThis operation could not have been carried out successfullywithout the active participation of Total Oil Marine drillingteam (V.Bordmann, P.Bouroumeau) and reservoir team(I.Potapieff, L.Schirrer, S.Lheure). The authors thankC.Sweeney and R.Tange of Halliburton Energy Services fortheir help in preparing this paper. Special thanks to all thepeople involved in this treatment in particular the people fromthe MV Skandi Fjord.

References1. M.S. Van Domelen, R.C. Jacquier, M.W. Sanders, Halliburton,

‘State-of-the-art fracturing in the North Sea’, paper OTC 7890,presented at the Offshore Technology Conference, Houston,Texas, May 1-4 1995

2. G.A. Gabriel, S.R. Erbstoesser, Exxon Production Research Co.,‘The design of Buoyant Ball Sealer Treatments’, paper SPE13085 presented at the 59th Annual Technical Conference andExhibition held in Houston, Texas, September 16-19 1984.

3. S.R. Erbstoesser, Exxon Production Research Co., ‘ImprovedBall Sealer Diversion’, paper SPE 8401 presented at the 54th

Annual Technical Conference and Exhibition of the Society ofPetroleum Engineers of AIME, held in Las Vegas, Nevada,September 23-26 1979.

SI Metric Conversion Factors

bbl x 1.589 E-01 = m3

ft x 3.048 E-01 = m°F-32 / 1.8 = °Cpsi x 6.894 E+00 = kPa1 bar = 100 kPalbm x 4.536 E-01 = kgcp x 1.0 E-03 = Pa.sgal x 3.78 E+00 = l

TABLE 1 : DETAILED ANALYSIS PER LAYER OFTHE PLT PERFORMED IN MAY 1997.

Layer h perf.(m)

Nr ofPerf.

Kh(md.m)

Qg(S m3/d)

Skin

B1a 6 118 7.95 29874 6.7B2a 8.5 167 10.69 18174 40.6B2b 13.8 271 na 0B2c 6 118 9.27 23556 23.5B2d 2 39 na 0B3a 8.6 170 3.1 30498 0.9B3b 12 236 8.71 42432 16.2B3c 5.5 108 na 0B3d 5.5 108 na 0C1a 3.5 69 3.81 31746 1.7

C1b-f 25 492 4.28 12324 21C1g 2 39 na

Note: Most of the layers are damaged. Some layers are completelyplugged.

TABLE 2 : DETAILED FLUID FORMULATION USEDDURING THE FRACTURING TREATMENT

Description ConcentrationGal/Mgals

Liquid Gel Concentrate 72 (Eq. 50 lbs)

Acid pH buffer 2

Caustic 3

Delayed crosslinker 2,5

KCl 2 %

High Temp oxidising breaker 0,05-0,1

TABLE 3 : DETAILED BREAKER CONCENTRATIONUSED DURING THE TREATMENT

Description Sl. Vol(gals)

Breaker Conc. gal/M Rate(bpm)

Pad 1 6000 0,05 20

Proppant ramp 1 5500 0,05 20

Pad 2 – 7 5000 - 6500 0,1 20

Proppant rampStage 2 –7

5500 - 8000 0,1 20

TABLE 4 : DETAILED ROCK STRESS ANALYSISLAYER PER LAYER

Name TVD Qg Pres Minorstress

Majorstress

Nb of

of layer m Km3/d psi psi psi Perf.

B1a 3864 30 4582 8569 10471 118

B2a 3913 18 5916 9325 11251 167

B2b 3951 0 7250 10064 12008 271

B2c 3984 23 5843 9403 11364 118

B2d 4002 0 7250 10146 12116 39

B3a 4009 30 6336 9694 11667 170

B3b 4055 42 7757 10489 12485 236

B3c 4075 0 7250 10264 12269 108

B3d 4090 0 7250 10288 12301 108

C1a 4122 31 6061 9737 11765 69

C1b 4151 6133 9820 11863 C1c 4156 6133 9828 11874 C1d 4167 12 6133 9846 11897 492

C1e 4174 6133 9857 11912 C1f 4181 6133 9869 11926 C1g 4194 na 6133 9890 11954 39

Note : minimum and major horizontal stresses as a function of thepore pressure. Results derived from rock mechanics studies.

SPE 54740 BALL SEALER DIVERSION WHEN FRACTURING LONG AND MULTIPLE TRIASSIC SAND INTERVALS 7ON ALWYN FIELD, NORTH SEA

TABLE 5 : MAIN FRAC DESIGNDescription Sl. Vol

(gals)Init Prop

(ppg)Fin Prop

(ppg)Prop(lbs)

Nb ofballs

sealer

Rate(bpm)

Pad 1 6000 0 0 0 0 20

Proppant ramp 1 5500 1 5 16500 60 20

Pad 2 5000 0 0 0 0 20

Proppant ramp 2 5500 1 5 16500 85 20

Pad 3 5500 0 0 0 0 20

Proppant ramp 3 5500 1 5 16500 60 20

Pad 4 5500 0 0 0 0 20

Proppant ramp 4 5500 1 5 16500 85 20

Pad 5 6000 0 0 0 0 20

Proppant ramp 5 5500 1 5 16500 120 20

Pad 6 6000 0 0 0 0 20

Proppant ramp 6 5500 1 5 16500 40 20

Pad 7 6500 0 0 0 0 20

Proppant ramp 7 8000 1 7 32000 0 20

30# Linear gel 6100 0 0 0 0 20

LO-TOX diesel 3600 0 0 0 0 20

Sea water 630 0 0 0 0 20

TABLE 6 : COMPARISON, LAYER BY LAYER, OFPI BEFORE FRAC AND AFTER FRAC

Layer PI beforeKm3/d/bar

PI afterKm3/d/bar

B1a 0.11 0.78B2a 0.03 0.36B2b Na NaB2c 0.08 0.19B2d Na NaB3a 0.05 0.3B3b 0.07 0.25B3c Na NaB3d Na NaC1a 0.11 NaC1b+ 0.04 0.45

200 km

Alwyn

Aberdeen

Shetland

Fig.1 : Alwyn North Field location.

8 P.BAYLOCQ, J.J.FERY, L.PARRA, E.DERBEZ SPE 54740

Fig.2 : 3/9a-N34 Reservoir log

Fig.3 : 3/9a-N34 completion schematic

Fig.4 : Optimum number of ball sealers to create an efficientdiversion, for 6spf and 60° phasing perforation guns.

SPE 54740 BALL SEALER DIVERSION WHEN FRACTURING LONG AND MULTIPLE TRIASSIC SAND INTERVALS 9ON ALWYN FIELD, NORTH SEA

Figure 5 : Detailed minifrac pressure behavior

Figure 6 : Minifrac pressure decline

Figure 7 : Temperature Log

Figure 8 : Balls diversion effect during main treatment

Figure 9 : Local ‘screen out effect

0

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7:10

7:21

7:32

7:42

7:53

8:04

8:15

8:25

8:36

8:47

8:58

0

5

10

15

20

25

30

35

40

45

50

Rate (bpm)

Calc BH Pressure (psi)

BH proppant Conc.

10000

10200

10400

10600

10800

11000

8:00

8:01

8:02

8:03

8:04

8:05

8:06

8:07

8:08

8:09

8:10

8:11

8:12

0

5

10

15

20

25

Balls @ perfs

BH Pressure

BH Prop Conc

10 P.BAYLOCQ, J.J.FERY, L.PARRA, E.DERBEZ SPE 54740

Fig. 10 : Schematic of surface installation

MSR

Sandsieve

Pump

Surface test tree

Production tree

Coflex

South BoomNorth Boom

Production lines

Choke manifold

Data header

Sand Filters

North & SouthBooms

Rig