z-99 successful pilot project of water conformance in a ... · z-99 successful pilot project of...

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EAGE 67th Conference & Exhibition — Madrid, Spain, 13 - 16 June 2005

Abstract

In December 2003, a pilot polymer gel treatment was implemented in the Vizcacheras Fieldlocated in Western Argentina’s Cuyo Basin. The project included one treatment in an injectorwell with the main objective of improving volumetric sweep efficiency in the subject patternand reducing water injection rate and water production rates in producers.The Vizcacheras Field is a mature waterflood that was discovered in 1965. As of November2004 field production was 9000 BOPD from 171 producing wells with an average water cutof 96%. The production comes from two heterogeneous fluvial sandstone formations:Papagayos and Barrancas. The 32% of total production is coming from Barrancas formationwhich is the target of this project.This conformance improvement project began in 2002 with laboratory studies, initial polymergel treatment design, tracer studies and numerical simulation. The gel chemistry included amedium molecular weight, partially hydrolyzed anionic polyacrylamide polymer crosslinkedwith chromium triacetate. After a period of monitoring, interesting results have been observedin the affected wells to encourage a first step expansion project.The paper will describe the petrophysical characteristics of the Barrancas formation, includingan overview of the field production and waterflood history. The design, implementation andevaluation of the polymer gel pilot project will also be discussed.

Introduction

The Vizcacheras Field is part of a larger block of the same name located in the southeasternregion of Cuyana Basin in the province of Mendoza, Argentina. The western boundary of thefield is the La Ventana Area and the northern boundary is the West Zampal Area (Figure 1).

340

CUYANA

CUENCA

MENDOZA

MENDOZA

10KM

VIZCACHERAS

RIO TUNUYAN

LA VENTANA

EMBALSEEL CARRIZAL

RIO MENDOZA

RIO TUNUYAN

BARRANCAS

CAÑADA DURA

Figure 1–Map of Area of Interest

The field includes two primary reservoirs: the Barrancas Formation and the PapagayosFormation. As of November 2004, the total field production was 1,494 m3/day (9,397

Z-99 Successful Pilot Project of Water Conformancein a Mature Field. Vizcacheras, Argentina.

C. NORMAN1, J.DE LUCIA2 AND L. STRAPPA3

1Tiorco Inc., Englewood, Colorado , U.S.A.2REPSOL YPF, E&P-UEM-Reservorios, España 955, PC 5500 Mendoza, Argentina

3REPSOL YPF , E&P-UEM-Reservorios, Jorge Newbery 1350, PC 5613 Malargue, Argentina

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barrels/day) at an average water cut of 96.1%. Cumulative oil production at that date was52.16Mm3 (328 Million barrels).

Objective

In December 2003, a water conformance pilot was performed in the Barrancas Formation.The Barrancas Formation discovery well was the LJx-1 drilled in 1962, although initial oilproduction did not occur until mid-1966. The project objective was to reduce injectivity inthe high permeability layers (“thief zones”) between the injection wells and the associated producing wells, thereby diverting injected water into unswept rock. If successful, the pilotwas expected to include several benefits: Improved volumetric (vertical and areal) sweep efficiency in the injector-producer

pattern; Increased oil recovery factor due to incremental oil production; Reduced water injection volumes and, consequently, less water production.

History

Geologic Background

The structure in which the Vizcacheras field was developed is an erosional fault block formedby a continental rift of Triassic age. The valley fill is predominantly clastic and pyroclastic,with lesser amounts of volcanics. The current structure corresponds to the Andean Tertiarydeformation.The Barrancas Formation is composed primarily of sand-conglomerate bodies interbeddedwith impermeable shales. The productive intervals are heterogeneous, laterally and vertically,which results in a degree of uncertainty in the correlation of sand bodies. The thickestintervals are found in the north and east of the Vizcacheras block. Toward the south and west,the productive facies diminish in thickness and reservoir quality, eventually pinching out.

Structure

The Vizcacheras structural high is composed of an asymetrical fold with a dip of 2°E on theeastern flank. The western flank is almost horizontal. The axis of the structure is orientedNNW—SSE dipping to the North.

Figure 2–Stratigrafic ColumnThe anticline is characterized byapproximately vertical East-West faultsthat do not exhibit significant separation.Based on more clearly defined structuresin the area, it is believed that there is acertain degree of dynamic horizontaldisplacement. This type of deposition,with very limited fault separation, impliesthat the faults are not permeabilitybarriers, but instead act as conduitsbetween offset layers. Also, there areNW—SE fault trends with origins in theAndean compression.

Stratigraphy

Figure 2 is a representation of thestratigraphic column of the sedimentstypically found in the Cuyana Basin.

V V V V V V V V

V V V V V V

V V VV V

V VV

VV V

VV V

V

EDAD FORMACION LITOLOGIASYSTEM TRACTS FA

SETE

CTO

NIC

A

RES

ERVO

RIO

S

RO

CA

MAD

RE AMBIENTE

SEDIMENTARIOESPESOR

FLUVIALEOCENO DIVISADERO LARGO

JURASSICOCRETACICO

PAPAGAYOS

PUNTA DE LAS BARDAS

JUR

ASIC

OSU

PER

IOR

BARRANCAS

RH

AETI

ANO

NO

RIA

NO

RIO BLANCO

CACHEUTA

CAR

NIA

NO

TR

IAS

ICO

AST

BSTFST

HST

MFS

BASALTOS

ABANICO ALUVIALFLUVIAL

YBARREALPO

STRI

FTN

EUQ

UEN

?TA

RD

IO

FLUVIAL

DELTAICO

LACUSTRE

TEM

PRAN

O POST

RIFT

TST

LSTDELTAICO

PLANICIE ALUVIALPOTRERILLOS

LADINIANO

ANSIANO LAS CABRAS

SCYTIANO RIO MENDOZA

SYN

RIF

T

VOLCANICOSLACUSTRE

FLUVIAL

ABANICO ALUVIAL

0 -1500 - 100

0 - 200

0 - 160

200 - 900

40 - 450

100 - 800

PALEOZOICO BASAMENTO

PRER

IFT

100 - 700

50 - 200

Y Y Y Y Y

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The Rio Blanco formation is the current economic basement rock in the Vizcacheras block.There have been no economic hydrocarbon discoveries below this formation. The Rio Blancois a clastic/epiclastic rock (reworked volcanics) that was deposited in a deltaic-lacustrineenvironment with a marked fluvial influence toward the top.The Barrancas Formation lies on an unconformity above the Rio Blanco formation in ageological event during the Jurassic, which initiated the beginning of the formation of a largefault block with a NNW-ESE orientation. Five flow units have been defined by geologicanalysis and well tests (from bottom to top): Blue, Yellow, Green Red and Grey. Theseintervals are composed of discontinuous sand bodies interbedded between thinner, lowpermeability shale stringers.The volcanic layers that partially overlay the Barrancas Formation belong to the Punta de lasBardas formation, deposited simultaneously with the natural fractures that developed as acontinuation of the tensional Jurassic forces. This formation is composed of andesite layersinterbedded with pyroclastic flows and thin horizontal pelitic layers. The Punta de las Bardasis considered as the regional seal for the productive hydrocarbon reservoirs.During the Eocene, an accumulation of fluvial clastic sediments, known as the Papagayosformation, were deposited above the Punta de Las Bardas formation. Overlying the Papagayosis the Divisadero formation, composed of fine clastics with abundant evaporites (chalk,anhydrites) deposited in eolian and playa lake environments.Finally, the Mariño formation consists of thick clasic accumulations that were developed asan alluvial fan, with evidence of a subsequent temporary aluvial event. The source material isthe erosion of sediments that were exposed by a Western uplift.

Production History

As mentioned above, initial oil production from the Barrancas formation in the VizcacherasField occurred in mid-1966 with the completion of the Vi-7 well. Peak oil productionoccurred in 1968 with 3,086 m3/day at an average water cut of only 5%.At the end of 1991, a workover campaign was implemented in order to increase oil productionfrom the Barrancas formation. As a result, oil production increased from 480 m3/day to 700m3/day (see Figure 4).At the beginning of 1996 a pilotsecondary recovery project wasimplemented that included establishingfive patterns in an inverted seven spotconfiguration. In 1997 and 1998 theproject was expanded to include a total of20 injection wells in inverted seven spotpatterns.Figure 3 indicates the currentdevelopment scheme within theBarrancas and Papagayos reservoirs inthe Vizcacheras field.At the present time, the Barrancasformation production comes from 75wells that produce a total of 498 m3/dayof crude oil with an average water cut of95.6%. Cumulative oil production is14,555 Mm3, which translates to arecovery factor of 39.6%. Figure 4includes a historical production profile asof November 2004.

Figure 3 - Map of Well Locations

VI-1

2

3

4

5 67

8

9

10 11

12

13

14

15

17

18

19

20

21

22

23

24

25

26

28

29

30

31

32

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42 43

44 45 46 47

48 49 50 51 52 53 54 55

56 57 58 59 60 61

62 63 64 65 66 67 68

70 71 72 73 74 75

77 78 79 80 81

85 86 87 88

91

9293

9495

97 98 99 100 VI-101 102 103 104

105 106 107 108

109

110

111 112 113 114 115 116 117

118 119 120 121 122 123

124 125 126 127 128 129 130 131

133

134 135 136 137 138 139 140

141 142 143 144 145 146 147

148 149 150 151 152 153 154 155

156

157 158 159 160 161 162

165 166 167 168 169

171 172 173 174 175

176

177

178

179

180 181 182 183

184 185 186 187 188

189 190

191

192

193

194

195

196 197 198

199 200 201

204 205

207

208 209

210

211

212

213

214

215 216217 218

219 220 221

222

223 224 225

226 227

228

229 230

231

232

233234

235

236

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238239

240

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258259

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264 265 266

267 268

269

270

271

272

273

274275276

277

278 279

280

281 282

283

284

285 286287

288

289

290

VI-1001

1002

VI-1003

1004

VI-1005

1006

VI-1007

VIN-1

VIO-1

1008

1009

LJ-14

1010

LJ-5LJ-7

LJ-8

LJ-1

LJ-6

2548000 2550000 2552000 2554000 2556000 2558000 2560000 2562000

6276000

6278000

6280000

6282000

6284000

6286000

6288000

6290000

6292000

6294000

Limite

Estedel Yacim

iento

Oil Producer WellShut Off Well

Dry Well

REFERENCES

Disposal Well

Inyector Well

F. PapagayosArea Productiva

F. BarrancasArea Productiva

VI-1

2

3

4

5 67

8

9

10 11

12

13

14

15

17

18

19

20

21

22

23

24

25

26

28

29

30

31

32

33

34

36

37

38

39

40

41

42 43

44 45 46 47

48 49 50 51 52 53 54 55

56 57 58 59 60 61

62 63 64 65 66 67 68

70 71 72 73 74 75

77 78 79 80 81

85 86 87 88

91

9293

9495

97 98 99 100 VI-101 102 103 104

105 106 107 108

109

110

111 112 113 114 115 116 117

118 119 120 121 122 123

124 125 126 127 128 129 130 131

133

134 135 136 137 138 139 140

141 142 143 144 145 146 147

148 149 150 151 152 153 154 155

156

157 158 159 160 161 162

165 166 167 168 169

171 172 173 174 175

176

177

178

179

180 181 182 183

184 185 186 187 188

189 190

191

192

193

194

195

196 197 198

199 200 201

204 205

207

208 209

210

211

212

213

214

215 216217 218

219 220 221

222

223 224 225

226 227

228

229 230

231

232

233234

235

236

237

238239

240

241

242

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244

245

246

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248

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258259

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261

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264 265 266

267 268

269

270

271

272

273

274275276

277

278 279

280

281 282

283

284

285 286287

288

289

290

VI-1001

1002

VI-1003

1004

VI-1005

1006

VI-1007

VIN-1

VIO-1

1008

1009

LJ-14

1010

LJ-5LJ-7

LJ-8

LJ-1

LJ-6

2548000 2550000 2552000 2554000 2556000 2558000 2560000 2562000

6276000

6278000

6280000

6282000

6284000

6286000

6288000

6290000

6292000

6294000

Limite

Estedel Yacim

iento


Dry Well

REFERENCES

Disposal Well

Inyector Well

VI-1

2

3

4

5 67

8

9

10 11

12

13

14

15

17

18

19

20

21

22

23

24

25

26

28

29

30

31

32

33

34

36

37

38

39

40

41

42 43

44 45 46 47

48 49 50 51 52 53 54 55

56 57 58 59 60 61

62 63 64 65 66 67 68

70 71 72 73 74 75

77 78 79 80 81

85 86 87 88

91

9293

9495

97 98 99 100 VI-101 102 103 104

105 106 107 108

109

110

111 112 113 114 115 116 117

118 119 120 121 122 123

124 125 126 127 128 129 130 131

133

134 135 136 137 138 139 140

141 142 143 144 145 146 147

148 149 150 151 152 153 154 155

156

157 158 159 160 161 162

165 166 167 168 169

171 172 173 174 175

176

177

178

179

180 181 182 183

184 185 186 187 188

189 190

191

192

193

194

195

196 197 198

199 200 201

204 205

207

208 209

210

211

212

213

214

215 216217 218

219 220 221

222

223 224 225

226 227

228

229 230

231

232

233234

235

236

237

238239

240

241

242

243

244

245

246

247

248

249

250

251

252

253

254

255

256

257

258259

260

261

262

263

264 265 266

267 268

269

270

271

272

273

274275276

277

278 279

280

281 282

283

284

285 286287

288

289

290

VI-1001

1002

VI-1003

1004

VI-1005

1006

VI-1007

VIN-1

VIO-1

1008

1009

LJ-14

1010

LJ-5LJ-7

LJ-8

LJ-1

LJ-6

2548000 2550000 2552000 2554000 2556000 2558000 2560000 2562000

6276000

6278000

6280000

6282000

6284000

6286000

6288000

6290000

6292000

6294000

Limite

Estedel Yacim

iento


Dry Well

REFERENCES

Disposal Well

Inyector Well


Dry Well

REFERENCES

Disposal Well

Inyector Well


Dry Well

REFERENCES

Disposal Well

Inyector Well





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Figure 4–Historical Production Profile, Barrancas Formation

The production mechanism in the Barrancas reservoir is single phase fluid expansioncombined with a moderate natural water drive. Reservoir temperature is 98ºC. Averagepermeability, porosity and residual oil saturation are 500 md, 17% and 25%, respectively.The following table summarizes the status of all wells and selected statistical data as ofDecember 2004.

DETAIL VALUETOTAL WELLS DRILLED 156ACTIVE PRODUCING WELLS 76INJECTION WELLS 21WATER DISPOSAL WELLS 17CRUDE OIL PRODUCTION (m3/d) 498.7TOTAL FLUID PRODUCTION (m3/d) 10567AVERAGE WATER CUT (%) 95.6WATER INJECTION (m3/d) 9500CUMULATIVE OIL PRODUCTION (Km3) 14555

Table 1–Current Development Status of the Barrancas Formation

Brief Description of Polymer Gel Technology

Polymer gels have proven to be effective in improving areal (Ea) and vertical (Ev) sweepefficiency in mature waterfloods that exhibit water channeling. In the context of this paper,polymer gel is defined as a partially hydrolyzed polyacrylamide polymer with chromictriacetate as the crosslinking agent. This chemistry has been patented by Marathon OilCompany under the trade name Marcit™. During injection, polymer gels flow naturally into the highest permeability channels that aretypically the zones with highest water saturation. The objective is to reduce the permeabilityto water in these “thief” zones so that water injected subsequent to the gel treatment will contact previously unswept rock, presumably with lower permeability and higher oilsaturation.Subsequent to injection of the gelant solution, a three dimensional gel network is formed inthe reservoir. Normally, final gel strength is achieved in 3-5 days at higher reservoir

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temperatures. Polymers used in this type of gel application typically have a molecular weightof 8-13 MM amu and a hydrolysis of 8-15%.Marcit® gels can withstand reservoir temperatures up to 120°C. Extensive laboratory andfield case histories confirm that these gels can be mixed in water with high concentrations ofdivalent ions (Ca++, Mg++) and H2S. In the Vizcacheras field, the formation water containsa concentration of divalent ions in the range of 2200—2400 ppm and total disolved solids(TDS) of 70,000 ppm. However, in this pilot the gels were mixed in fresh water for tworeasons: (1) laboratory tests indicated that gels could be formed at lower polymerconcentrations in fresh water (vs. produced water); and (2) The produced water quality wasvariable, and at times included an unacceptably high concentration of oil for mixing stablegels.The chemical structure of this type of polymer is shown below, where M+ indicates K+ orNa+. Y and X represent the amide and carboxyl groups, respectively.

CH2 CH CH2 CH

CO Y CO X

NH2 O - M +

As indicated above, partially hydrolyzed polyacrylamide is a polyelectrolyte with negativecharges on the carboxyl group. This implies strong interactions between the polymer chainand the cations present in the solvent, particularly in polymers with higher percentages ofhydrolysis.The viscosity in this type of polymer solution is a function of: (a) the molecular weight of thepolymer (higher molecular weight higher viscosity) and (b) the elongation of the polymermolecule due to the anionic repulsion between different polymer molecules as well asbetween different segments within the polymer molecule.There have been many studies of the effect of water salinity on the viscosity of partiallyhydrolyzed polymers. Polymer solution viscosity diminishes as salt (e.g, KCl, NaCl)concentration increases. The presence of positively charged ions diminish the anionicrepulsion; that is, inhibiting the elongation of the polymer molecule which decreases theviscosity of the polymer solution. Divalent cations have a much more pronounced effect onpolymer viscosity than monovalent ions.An aqueous solution of amide groups will hydrolyze to a certain point depending ontemperature and PH. Sufficient concentration of divalent cations can increase polymerhydrolysis to the point that the polymer precipitates in the mix water or in the reservoir. Thereaction between divalent cations and carboxyl groups is shown below. Apparently, a strongbond can be generated between a divalent ion and two carboxyl groups in the same polymermolecule.

CH2 CH + H2O CH2 CH + NH4+

CO CO

NH2 O -

In order to avoid this undesired result and form a more robust structure with a lesser degree ofhydrolysis, a metal ion (crosslinker) such as Cr+3 can be introduced which attaches to theanionic charge of the polyacrylamide. The resulting molecular structure is much moreresistant to higher temperatures and salinity.Another consideration is mechanical degradation, that is, rupture of the polymer molecule thatcan occur if the polymer solution is subjected to certain mechanical stresses such as valves in

6

downhole mandrels, progressive cavity pumps (PCP) and centrifugal pumps. In the case ofdownhole mandrels, this effect is minimized if the mandrel valves are removed prior to gelinjection. One study1 has documented that polyacrylamide gels crosslinked with chromictriacetate (Marcit® gels) recover, or “heal” from the shear effect of passing through perforations. This may be due in part because the injected solution, or “gellant” becomes a fully formed gel as a function of time and temperature after placement in the reservoir.

Pilot Project Design

In some cases, conformance can be improved mechanically. Zones can be isolated, forexample, with downhole injection mandrels. Polymer gels were selected for application in theVizcacheras field for several reasons:

Some water channeling had been observed between injector and producer wells Several injection wells had mechanical problems that precluded selective injection; Casing integrity was questionable in many injection wells; Case histories in analogous fields indicated that the Vizcacheras field was a good

candidate for polymer gel conformance technology.

Laboratory Tests 2

In mid-2001, water samples provided by Repsol-YPF were analyzed by Tiorco, Inc. inDenver, Colorado USA in order to evaluate the stability of polymer gels at reservoirconditions and develop a range of polymer and crosslinker concentrations for application inthe Vizcacheras field (Table 2).

TIORCO, INC., LABORATORY - BOTTLE TESTS FOR POLYMER GELS - CUSTOM GEL DESIGN

COMPANY: REPSOL-YPFFIELD: Vizcacheras POLYMER: Water-Cut® 204WATER: Lab-simulated water per formulation of CROSSLINKER: Water-Cut® 684

Brandi Plant 192-97 (Fresh Water) STORAGE TEMPERATURE: Room

WC-100 WC-684TEST TUBE CONC. CONC. GEL EVALUATIONS WITH TIME

NUMBER PPM PPM Cr+3 4 HOURS 24 HOURS 48 HOURS 1 WEEK 2 WEEKS 1 MONTHn n+ n+ s+ g- g

VFW-1R 3000 75 0 1 1 2 3 5

n n+ n+ s g- gVFW-2R 3000 37.5 0 1 1 2 3 4

n s- g- g g e-VFW-3R 4500 112.5 0 1 3 4 5 5

n n+ s g- g- g+VFW-4R 4500 56.25 0 1 2 3 4 5

n s+ g g g+ e-VFW-5R 6000 150 0 2 4 6 7 9

n s g- g- e- e-VFW-6R 6000 75 0 2 3 6 7 8

n+ g g+ e- e- eVFW-7R 9000 225 0 5 7 8 8 9

n g- g e- e- eVFW-8R 9000 112.5 0 4 6 8 9 9

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STORAGE TEMPERATURE: 98ºC / ~208ºF

1 HOUR 24 HOURS 72 HOURS 1 WEEK 2 WEEKS 1 MONTHn+ g- g- g- s+ s+

VFW-1H 3000 75 1 3 3 3 2 2

n+ s+ s+ s+ n+ n+VFW-2H 3000 37.5 1 2 2 2 1 1

s g+ g g g gVFW-3H 4500 112.5 2 7 4 4 4 4

n+ g- s+ s+ s+ s+VFW-4H 4500 56.25 1 3 2 2 2 2

g- e- g+ g g gVFW-5H 6000 150 4 8 6 5 5 5

s g g- g- s+ s+VFW-6H 6000 75 2 5 4 3 2 2

e- e e e- e- g+VFW-7H 9000 225 9 9 9 8 8 7

g g g g g gVFW-8H 9000 112.5 6 7 5 5 4 4

Table 2 –Laboratory Tests

References:.n: no sign of gelation.s: slight tendency to gel.g: good gel elasticity.e: excellent gel elasticity

Table 2 indicates that at a polymer concentration of 3000 ppm, only a weak gel is formed. Atlaboratory conditions, polymer concentrations of 4500 ppm and above crosslinked withchromic triacetate at a ratio of 40:1 were required in order to observe strong gels. However,the gel treatment was performed in the field at a polymer concentration of 3000 ppm for thefollowing reasons: Dehydration of the polymer gel solution in the reservoir may increase polymer

concentration. It is impossible to duplicate the anerobic reservoir environment in the laboratory. Several

studies have shown that even minute oxygen concentrations can degrade polymer gels,particularly at high temperatures3,4 . Therefore, gel strengths in the reservoir mayapproximate those found at room temperature in the laboratory.

Case histories clearly demonstrate the positive correlation between gel volume andincremental oil response in injection well gel treatments5,6. Therefore, injecting asignificant gel volume was a priority. Shortly after the gel treatment began, well pressureresponse dictated that the treatment be carried out at lower polymer concentrations inorder to inject the designed gel volume.

Figure 5 (below) is a graph of polymer viscosity vs. temperature at a concentration of 3000ppm for the polymer selected for the Vizcacheras pilot. Tiorco’s trade name for this polymer is WC-204. Note the effect of salinity on polymer viscosity.

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3000 ppm WC-204

0

10

20

30

4050

60

70

80

90

0 20 40 60 80 100

Temperature, ºC

Vis

cosi

ty,c

ps

Vizcacheras Fresh Water Vizcacheras Produced Water

Figure 5–Polymer Viscosity vs Temperature

Selection of Pilot Injection Well

The Vi-144 pattern (Figure 6) was selected for the pilot polymer gel project according to thefollowing criteria. The Vi-144 pattern includes four “first line” producing wells and seven “second line”

producing wells. It was believed that the large number of associated producing wellswould increase the potential for a positive response in a relatively short period of time.

The producing wells in the Vi-144 pattern have responded well to water injection. Water channeling between Vi-144 and certain associated producing wells had been

documented with tracers. The Vi-144 injector had relatively high injectivity and low injection pressure. The

vertical injection profile, with % of water admission by layer, is shown in Figure 8. Reservoir studies indicated good connectivity in all four flow units (Red, Green, Yellow

and Grey) within the Vi-144 pattern.

Figure 6–Map of Water Conformance Pilot Pattern Vi-144

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Figure 7 shows the electric log of injection well Vi-144. Figure 8 is a summary of thehistorical injection vertical profile for Vi-144.

1860

1865

1870

1875

1880

1885

1890

1895

1900

1905

1910

1915

1920

1925

1930

Verde

Amarilla

Roja

Gris

Figure 7–Log of Injection Well Vi-144

1868

1870

1870.51872

1873.5

187518761877 4

18791880 4 9

1880.51882

18831885

1886.51888

1893.5

1895.5

1896.5

1901

19051906

1907.51908.5

1913100

33.6

26.7

39.7

780 m3/d

55 Kg/cm2

9

11

100

46

2

7

4

21

100

25.8

37.3

22.2

15

20 de Agosto de 2002

625 m3/d

48 Kg/cm2

7 de Noviembre de 2003

750 m3/d

45 Kg/cm2

23 de Octubre de 200225 de Julio de 2000

427 m3/d

10 Kg/cm2

100

47.7

4

4

10

21

100

110 Kg/cm2 100 Kg/cm2

4

4

2 de enero 1998 15 de Julio 1999

445 m3/d245 m3/d

37.4

45.5

100

7

66.6

9

26.4

4 de febrero de 2002

887 m3/d

50 Kg/cm2

100

32.6

12

55.1

Figure 8–Vertical Injection Profile for Injector Vi-144

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Tritium Tracer Survey in the Red Sequence

In December 1999 a tritium tracer survey was initiated in the Red sequence of injection wellVi-144 with the objective of determining the degree of connectivity between the injector andassociated producers and to calculate the pore volume in this sequence. This informationwould be useful in the design of the polymer gel conformance pilot.An analysis was performed based on the response obtained after injecting a water slug markedwith tritium (15 Ci, low level Beta emission 55.5 GBq, half life 12.7 years) in injector Vi-144on December 15, 1999. At that time the injection rate was 164.7 m3/day.

Analysis of Simulated Response 7

The tracer survey included calculation of the following: (a) connectivities, based on thepercentage of the injected tracer detected at each producing well; (b) the swept area betweeninjector Vi-144 and each associated “first line” producer; (c) relationship of central streamlines to movable pore volume (MPV); and (d) the relative “time of flight” (TOF) of a hypothetical particle from injector Vi-144 to the each of the “first line” producing wells indicated below.

Base Case and Central StreamlinesInjector - Producer TOF (rel) Swept Area [m2] Connectivity [%]

VI-144, VI-249 1.00 111602 41

VI-144, VI-1007 2.55 33958 18

VI-144, VI-246 2.07 93162 17

VI-144, VI-41 13.9 27749 5

VI-144, VI-242 2.65 60435 12

VI-144, VI-1001 19.9 50643 4

VI-144, VI-150 19.1 15533 3

The comparison between the field response and the streamline simulation results revealedsignificant differences in the pattern’s vertical and areal flow regime, suggesting the existence of “macro-heterogeneities” (i.e., highpermeability zones) in the VI-29—VI-135 flank. On theother hand, the lack of tracer response in wells VI-1001, VI-141 and VI-150 correspond to thelow connectivity and long TOF’s associated with these wells in the simulation. Pore volumes were calculated based on the swept areas indicated by the tracer.

Streamline Simulation Methodology

The base case streamline simulation for the VI-144 pattern waterflood assumed a multi-layerreservoir without crossflow. The model incorporated heterogeneity in terms of net thicknessof each layer, but quasi-homogeneity for viscosity, fluid saturations and porosity. However,the simulation did not consider anomalies (macroheterogeneities) in absolute permeability.The model simulated average areal response while the global response was developed usingvertical integration of the four flow units.

Field Response

A tracer response was noted in all four “first line” producing wells:VI-246, VI-249, VI-242 and VI-1007.Among the “second line” producing wells, a tracer response was received inVI-143, VI-29, VI-135 and VI-255, but not in VI-136, VI-41, VI-1001 and VI-150.

Calculation of Movable Pore Volume (MPV) affected by Conformance Project

MPV was calculated for the “Central Streamline Case” (i.e, areas effectively swept) in theRed sequence in order to assist in the design of the polymer gel conformance pilot. MPV of

11


186,433 m3 was calculated for the VI-144 pattern, of which 22,713 m3 could be affected bythe polymer gel. That is, 12% of the MPV would be the target of the polymer gel treatment.Case histories suggest that as a minimum, 5% of the estimated “thief zone” volume should be treated with polymer gels. A larger gel volume is preferred, given the positive correlationbetween gel volume and incremental oil response. In the present case, 5% of 22,713 m3 =7,143 barrels of polymer gel. The final gel design was 15,000 barrels of gel in order to takeinto consideration the pore volume of the other flow units.

Numerical Simulation 8

As an additional diagnostic procedure, a numerical simulation was performed in order topredict the oil response and incremental oil reserves from a 15,000 barrel polymer geltreatment in the VI-144 pattern.The simulation was performed by SURTEK, using the numerical simulator GCOMP, asoftware package that includes the option of simulating chemical processes in the reservoir.The same simulation software had been used to simulate primary + secondary recovery in partof the Vizcacheras field that includes the VI-144 pattern, so there was only nominalincremental cost associated with the gel simulation. The geological model was provided byRepsol-YPF engineers and geologists.There were several technical issues associated with simulating the effect of the polymer gelsthat were not resolved. Given the time constraints, it was decided to proceed with the fieldpilot. Therefore, the results of this simulation are not included in this report.

Design and Implementation of the Polymer Gel Treatment

As previously mentioned, the final design of 15,000 barrels was based on severalconsiderations, including:

The results of the streamline simulation Tracer results Analysis of RAP vs. Np curves in the VI-144 pattern Case histories in analogous fields Economics

The selected polymer and crosslinking agent (chromic triacetate) were Tiorco’s WC-204 andWC-684, respectively. The designed polymer concentration was 3000--7000 ppm crosslinkedwith chromic triacetate at a ratio of 40:1 (polymer:Cr+3). As mentioned above, it was decidedto mix the gels in fresh water.The gel injection rate was designed not to exceed 1250 barrels of gel/day (200 m3/day) at amaximum wellhead pressure of 1130 psi (80 Kg/cm2). Estimated surface fracture pressure forthe Barrancas formation is 1280 psi (90 Kg/cm2). Polymer gel treatments are usually designedto be placed below reservoir fracture pressure.In late November 2003 the gel treatment began in injector VI-144. A 3000 barrel slug of freshwater was injected first, followed immediately by the polymer gel solution at a rate of 1000bbl/day (160 m3/day). Due to the rapid pressure increase, the gel injection rate was reducedto 750 bbl/day (120 m3/day) early in the treatment.Surface pressure continued to increase in spite of the reduced injection rate, so it was decidedto add dry potassium chloride (KCl) to the fresh water in order to reduce the viscosity of thegelant. The initial KCl concentration was 40000 ppm, later reduced to 20000 ppm. Additionallaboratory tests were performed to confirm the stability of the gel with the indicatedconcentrations of KCl.Figure 9 includes a graph of injection rate, polymer concentration, wellhead pressure and HallSlope, based on hourly data recorded during the 19 day gel treatment. Based on the pressureresponse, the entire gel treatment was performed at a polymer concentration of 3000 ppm.

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Figure 9–Gel Treatment Job Log Graph

Five injection profiles were performed during the gel treatment in order to document whichflow unit(s) were taking the gelant and to record the change in the vertical profile during thegel treatment.Figure 10 is a chronological summary of the above mentioned injection profiles, includingcumulative gel injected at each point. The reader will note that the Yellow sequence received100% of the gelant for a period of time. The final injection profile was somewhat moreuniform than the initial log. However, Tiorco’s data base does not indicate a positive correlation between injection profiles and post-treatment oil response.

GRIS

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Figure 10–Injection Profiles during gel injection

13


Evaluation of Conformance Pilot

At the end of the treatment, the gel injection rate was 750 barrels/day (120 m3/day) at awellhead pressure of 800 psi (56 Kg/cm2). Although the stable pressure behavior confirmsthat it would have been possible to continue the gel treatment, budget considerations limitedthe gel volume to the original design of 15,000 barrels.

Response in the injection parameters

After the gel treatment, the injection rate was significantly reduced and the average wellheadpressure increased. The average pre-gel (2003) injection rate and pressure was 645 m3/day at52 Kg/cm2, respectively, compared to post-gel injection rate and pressure of 365 m3/day and60 Kg/cm2, respectively. See Figure 11.

Historia de Inyección Vi-144

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Jun-97 Dic-97 Jun-98 Dic-98 Jun-99 Dic-99 Jun-00 Dic-00 Jun-01 Dic-01 Jun-02 Dic-02 Jun-03 Dic-03 Jun-04 Dic-04

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Figure 11 –Injection History Vi-144

Figure 12 is a Hall Plot of the VI-144 injection well. The change in slope after the treatmentconfirms the reduced injectivity, which is a usually a desired result in polymer gelconformance treatments.

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Figure 12–Hall Plot Vi-144

14

Tracer Response after Gel Treatment

As previously mentioned, injection well VI-144 was treated with a Tritium tracer in the Redsequence prior to the gel treatment. The results confirmed water channeling between injectorVI-144 and associated producing wells in only 37 days in certain cases.In September 2004, nine months after the gel treatment, another tracer survey was performedin the Red sequence of VI-144. Samples taken in November and December 2004 confirm thetracer has not arrived at any of the offset producing wells. More time is needed to analyze thepost treatment tracer results and quantify the improvement in areal sweep efficiency.However, the initial tracer results indicate that the gel treatment has in fact been effective inchanging the flow regime within the VI-144 pattern, presumably diverting injected water intopreviously unswept zones.As part of the continued post treatment monitoring, the operator has performed severalinjection profiles (Figure 13). The variation in the vertical profile over time may reflect thechanges in flow regime within the reservoir.

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Figure 13–Post-Treatment Injectivity Profiles

Oil Production Response

Figure 14 is a production history for the VI-144 pattern, including oil production from allassociated wells. After the gel treatment, a sustained positive slope change is noted in thelogarithmic oil production curve. Total fluid production has remained relatively constant. Awell by well analysis revealed, as expected, that the oil response is not uniform among theproducing wells.

15


As of November 2004, the estimated incremental oil production from the VI-144 geltreatment is 7 m3/day (44 barrels/day).

StartWater

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Water Conformance Pilot Pattern (Vi-144)

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Flooding

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Water Conformance Pilot Pattern (Vi-144)

Figure 14–Injection and Production History

Estimation of Incremental Oil Reserves

Incremental oil reserves associated with the conformance pilot as of November 2004 areestimated from an analysis of “base case” and “incremental case” decline curves for the producing wells associated with injection well VI-144. The key assumptions include an initialincremental oil rate of 7 m3/day, declining harmonically until 2016 (concession expires).This preliminary analysis quantifies incremental oil reserves of 20,800 m3 (130,800 barrels)in the VI-144 pattern as of November 2004.The incremental oil reserves attributable to the gel treatment as of November 2004 are 20.8Km3. As indicated in Table 3, this represents 1.2% of the estimated OOIP in the VI-144pattern. This may prove to be a conservative estimate as more production data is collected.

Volumetric Reserve Data

Parameter Units Fm. BarrancasInitial Water Saturation % 43

Pore Volume Km3 3386.2Oil Formation Volume Factor RB/STB 1.1

OOIP Km3 1787.2Incremental Oil Reserves Km3 20.8

Recovery Factor (% OOIP) % 1.2Table 3–Volumetric Reserve Parameters

Economic Evaluation

An economic evaluation of the conformance pilot was performed, based on the forecastedincremental oil production as of November 2004. The total project cost was u$s 305,000, asdetailed in the following table.

16

Item Cost, Ku$s

Tracers 28Chemical Products &Services 257

Workover costs 15

Facilities 5

Total 305Table 4–Summary of Conformance Treatment Costs

Table 5 includes the crude oil price forecast used in the economic evaluation.

YearPrice

u$s/Bbl DiscountsNet Priceu$s/Bbl

2004 43.2 3.97 39.32005 35.0 3.97 31.02006 29.0 3.97 25.02007 27.0 3.97 23.02008 27.5 3.97 23.62009 28.1 3.97 24.12010 28.7 3.97 24.72011 29.2 3.97 25.32012 29.8 3.97 25.82013 30.4 3.97 26.42014 31.0 3.97 27.02015 31.6 3.97 27.72016 32.3 3.97 28.3

Table 5–Crude Oil Prices

Table 6 includes the evaluation’s economic indicators based on the incremental oil reserves asof November 2004 and the oil price assumptions from Table 5.

Economic Indicator Units Value at 100 %Working Interest

Incremental Oil Reserves (Km3) 20.9

Investment (Ku$s) 305

IRR. (%) 69.8

Layout (Meses) 23

NPV @ 10% (Ku$s) 754.8Development

cost/incremental Bbl (u$s/Bbl) 2.3Table 6–Conformance Pilot Economics

Pilot Expansion9

Based on the pilot results, additional conformance treatments were implemented in 2004,including a second gel treatment in VI-144 and two adjacent injection wells, VI-145 and VI-1002. The strategy in the 2004 expansion was to extend the incremental oil production trendin the VI-144 pattern and to generate a synergistic effect by treating adjacent injection wells,thereby surrounding common producing wells.

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References

1) Broseta, D., Marquer, O., Zaitoun, A., Baylocq, P., Jean-Jacques, F., “Shear Effects on Polyacrylamide/Chromium (III) Acetate Gelation, SPE Reservoir Evaluation &Engineering, June 2000, p. 204-208.

2) Laboratory Tests, Vizcacheras Field, Tiorco Inc., September 20013) Moradi-Araghi, A., Bjornson, G., and Doe, P.H., “Thermally Stable Gels for Near

Wellbore Contrast Corrections, SPE 18500, 19934) Rylos, R.G., “Elevated Temperature Testing of Mobility Control Reagents, SPE

12008, 19835) Portwood, J.T., Ricks, G.V., “Injection-side Application of MARCIT Improves

Waterflood Sweep Efficiency, Decreases Water-Oil Ratio and Enhances Oil Recoveryin the McElroy Field, Upton County, Texas”, SPE 59528, 2000.

6) Smith, J.E., “Practical Issues With Field Injection Well Gel Treatments”, SPE 55631, 1999.

7) Streamline Simulator, Analysis of Radioactive Tracers, VI-144, Microbes Inc., August2001

8) Numerical Simulation Evaluation of Polymer Gel Conformance Treatment Well Vi-144 of the Vizcacheras Barrancas Field, Surtek Inc., August 2001

9) Proposal for expansion of conformance project in the Vizcacheras Field, JP. De Lucia,Reservoir Engineer, Repsol-YPF, Vizcacheras Field, November 2004.

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