1998.176 Orinoco Belt, Cerro Negro Area Horizontal Well Evaluation

7/31/2019 1998.176 Orinoco Belt, Cerro Negro Area Horizontal Well Evaluation

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No. 1998.176

Orinoco Belt, Cerro Negro Area: Horizontal Well Evaluation

Marcos Briceo, Fernando Rodulfo, and Suni Surez, PDVSA-BITOR, Caracas,

Venezuela

Abstract

The horizontal drilling activity in Venezuela started in 1989

with two (2) wells, CI87 and CI97, which were completed in

the Orinoco Belt, one of the largest bitumen reservoir in the

world. The objective was to find the best exploitation scheme

and alternatives to increase the recovery factor.

Reservoir criteria to select the position of these wells was

focused on the petrophysical and reservoir characteristics like

sand quality, porosity, permeability, net bitumen sand, pres-

sure and waterbitumen contact depth.Actually, there are eight (8) horizontal wells drilled with 8

1/2 inch diameter production hole and completed open hole

with 7 inch slotted liner (0.0200.030 inch slot size) in a hori-

zontal length between 1,0002,722 feet.

The artificial lift systems used on these wells are rod pump-

ing and electric submersible pumps, with initial production

rates between 8002,000 BPD and productivity indexes in the

range of 2.06.0 BPD/PSI.

The objective of these paper is to show the preliminary pro-

duction results obtained with horizontal wells compared to

traditional wells (vertical, deviated and slant), as the first step

to look for a better exploitation scheme for the development ofthe total remaining reserves. Considering drilling and operat-

ing cost reduction and reservoir recovery factor improvement.

Introduction

The Orinoco Belt is one of the largest bitumen reservoir in theworld and for its exploitation was divided into four (4) sectors,from east to west: Cerro Negro, Hamaca, Zuata and Machete.In the Cerro Negro area, located between Anzotegui andMonagas state limits, about 120 km to the south of theMaturin City and 70 km to Puerto Ordaz City, PDVSABITOR is developing part of this accumulation to produce

bitumen for Orimulsion manufacturing (Figure 1).The total PDVSA BITOR area is around 180 square kilo-

meters. The estimated volume of bitumen originally in placein the area is 24.2 billion barrels in the Morichal Member with2.9 billion barrels of recoverable reserves associated to arecovery factor of 12%. This area has been divided into pro-duction blocks, being O16 and J20 the more developedblocks. Total field production is handled with two flow sta-tions, (O16 and J20), with an installed capacity of 45 and80 MBFD respectively. The total production potential of thefield is about 82 MBD with 265 wells.

Geological and ReservoirDescription

The Cerro Negro area, is a monoclinal of 24 soft dip

towards the north, cut by multiple faults, east to west oriented

as well as some smaller faults with northeast southwest azi-

muth, forming a 45 angle with the main fault (Figure 2)

Most of the faults are non-sealing, normal and extended more

than 15 km with vertical displacements between 50200 feet

Their vertical displacement increases to the north sector. Faul

identification with electrical logs is a difficult task due to the

presence of massive sands. The hydrocarbon accumulations

are controlled with stratigraphic traps; regional water-bitumen

contacts or gas-bitumen contacts were not identified originally

as reservoir limits.

The average thickness of the structure is 3,000 feet and it is

constituted by the Oficina Formation (medium to lower

Miocene) as the main reservoir rock on top of the Igneous-

Metamorphic Basement. The Oficina formation is divided into

16 units contained in four members: Morichal member (O16

to O11), Yabo member (O10 to O9), Jobo and Pilon mem-

bers (O8 to O4). Above Oficina lies the Freites Formation

(medium Miocene age) followed by Las Piedras Formation

(upper Miocene and Pliocene age). Sedimentation ends withthe Mesa Formation, (Pleistocene age), (Figure 3). In the Ofi-

cina Formation, with a fluvial deltaic origin, the massive

thick sands with shale intercalation are found, typical of a

periodic transgressive regressive sequence. In some region

the sands are communicated and in others they are not.

The petro-physical evaluation of the area is the result of the

study of 85 available wells with porosity logs and of 290 wells

with resistivity curves, as well as core analysis and wall sam-

ples taken in 4 wells.

The bitumen produced in the field comes totally from the

Oficina Formation-Morichal member, specifically from 4 res-

ervoirs denominated Mor90, Mor91 towards the north andMor92, Mor93 towards the south. Northern reservoirs are

3,450 feet deep, sand thickness is 275 feet thick, initial reser-

voir temperature and pressure is 130F and 1,126 psia respec

tively. Southern reservoirs are 2,500 feet deep, their thickness

is 300 feet, reservoir temperature is 120F and initial pressure

is 979 psia.


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Bitumen has an average API gravity of 8 degrees, its vis-

cosity is around 5,500 centipoise at reservoir conditions

(125F and 1,100 psi); rock permeability is between 1020

Darcies and porosity between 3235%. Rock and fluids prop-

erties are shown on Table 1.

Solution Gas Drive production mechanism represents the

most important source of energy of the reservoir, even though

the initial gas solubility is relatively low (80 scf/stb). It is

important to mention that sensitivity studies done in 1994

indicated that for a typical case, the final recovery could

decrease from 128%, if gas-bitumen ratio increases from 40

800 scf/stb. This result imposes a necessity to manage conser-

vatively the balance between pressure and production.

Recent laboratory experiments indicate that at controlled

conditions of pressure depletion, Cerro Negro bitumen

behaves as foamy oil

, characterized by small gas bubbles

trapped and moving with the bitumen, variable critical gas sat-

uration with pressure changes and the presence of a pseudo

bubble point. Actually, mathematical models are currently

being developed to represent this behavior, in order to repro-

duce production performance and to determine optimal fieldconditions to take advantage of this mechanism, increasing the

final recovery factor.

On the total area, a few wells have an original water-bitu-

men contact that is considered local, the aquifer extension and

its influence on the reservoir performance have not been deter-

mined. However, some wells produce with a high water cut

because water has abnormally advanced probably due to

mobility difference between water and bitumen, affecting

bitumen production rates instead of helping pressure mainte-

nance.

Recent field measurements have demonstrated that after 15

years and 120 MMBls of cumulative production surface sub-sidence is not present, indicating that unconsolidated sand

compaction mechanism has not contributed yet as a produc-

tion mechanism. However, studies indicate that below a cer-

tain reservoir pressure (500 600 psia) this mechanism can

contribute favorably to the final recovery factor.

Vertical, Deviated and Slant WellProduction Performance

Up to December 1997 and after 15 years of production the

field has produced 120 MMBls (5.4% of recoverable reserves)

out of 2.9 billion barrels of estimated reserves in the Morichal

Member with a 12% recovery factor. A total of 350 wells have

been drilled in the area (including exploratory wells), several

exploitation schemes have been used with different well

geometry, huff and puff steam injection and cold production.

The complete field performance is shown in Figure 4.

During 19821984, drilling vertical wells spaced 150 and

300 meters started as a preliminary experimental phase. Com-

pletions were mainly internal gravel packs on the northern

block (O16) and open hole gravel pack on southern block (J

-20), with 3-1/2 and 51/2 in. slotted liner (0.030 in. slot)

respectively. The artificial lift system was conventional

mechanical pump with diluent injection in the bottom to

reduce bitumen viscosity and aid lifting and surface transpor-

tation.

Internal gravel pack or open hole gravel pack selection was

made after drilling the production hole all the way to the igne-

ous metamorphic basement. This practice permitted to iden-

tify two local water bitumen contacts at 3,215 ft and 3,120 ft

below sea level on the north (O16) and one local water-bitu-

men contact at 2,475 ft below sea level on the south (J20).

The average bitumen cold production was between 150 to

250 BPD per well, after steam injection (huff and puff) wells

had initial rates of 600 barrels per day. The average reservoir

production rate during 1984 to 1991 was about 20 MBD with

200 BPD per well. Typical cumulative production in 150 mts

spacing for inside gravel pack completions is 312.900 bls and

492.230 bls for open hole gravel pack. For wells 300 mts

spacing in on open hole gravel pack and inside gravel pack

cumulative production is 740 mbls and 482 mbls respectively,

Figures 56.In several wells located in the north (O16) and south (J

20) the field cumulative production has been lower due to

early water irruption caused by the difference in the pressure

depletion rate between the areas with 150 and 300 meter spac-

ing, water/bitumen mobility and sand quality.

Between 1990-1996, commercial development has been

accomplished to support Orimulsion production. Up until

1992, the exploitation scheme selected includes deviated wells

in nine well clusters. The main objectives of this development

scheme were to increase well bore area across the whole Mor-

ichal Member and to minimize environmental impact.

Each cluster has one vertical well and eight deviated wells.On surface the wells are 1115 meters apart. Down hole

drainage points are spaced every 400 meters in a rhomboidal

shape with equilateral triangles formed between points.

Twelve clusters (96 deviated and 12 vertical wells) were

drilled. The casing design was 10-3/4 in. x 7 in., 5-1/2 in. slot-

ted liner (0.030 in. slot size) was run across the pay zone, 300

ft. and 600 ft thick and in open hole completions the produc-

tion hole was enlarged to 13 in. The artificial lift equipment

used was conventional mechanical pumping with diluent

injection down hole.

On the vertical wells resistivity and porosity logs were

taken to determine completion design of the remaining eight(8) wells. As expected, the wells located on northern block

(O16) were completed using inside gravel pack to control

water production and on the southern block (J20) all the

wells were complete using open hole gravel pack do to the

presence of massive sand without water bitumen contact.

Production rates per well varied between 250400 bpd.

Typical expected cumulative production per well for this

development scheme reaches 1,8 mmbls in open hole gravel

pack completions, Figure 7.


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In 1994, keeping the same well distribution at the surface

and spacing down hole, slant well drilling technology started

to be used. A total of 7 clusters (56 slant and 7 vertical wells)

were drilled In all the wells open hole gravel pack with 5 1/2

slotted liner in a 13 inch hole. The lifting design used is pro-

gressive cavity pump and production rates per well reached

450500 BPD. Cumulative production expected fir this wells

reaches 1,8 mmbls.

During the commercial development period, with the incor-

poration of slant and deviated wells, the total production of

the field increased up to 60 MBD with an average of 280 BPD

per active well. Vertical deviated and slant wells performance

is shown in Figure 8.

Horizontal Reentry andHorizontal Well ProductionPerformance

Between 1989-1990, two experimental horizontal wells were

drilled in north block, J20 (CI87 and CI97) across the O12 and O-15 sands with 2,000 and 1,000 feet horizontal sec-

tion respectively. In these wells casing design is 13 3/8 in. x 9

5/8 in., well completion is 8 1/2 in open hole with 7 inch slot-

ted liner. Conventional artificial lift equipment is used with

diluent injection down hole.

Initial rates for these wells were 1,000 bpd, even though

they had different horizontal section lengths and after 9 years

of production the wells have declined an average of 5% per

year, today the production level remains close to an average of

700 bpd. The cumulative production of these wells are 800

MBls and 600 MBls respectively, with 4 and 3% of the

reserves already recovered.Based on the excellent results obtained on the experimen-

tal, a horizontal re entry campaign was designed and

implanted to recover remaining reserves from wells mechani-

cally damaged or from wells with high water production. This

technique also allowed the incorporation of inactive wells and

cost reduction by using existing facilities, minimizing the

number of new wells needed to maintain the production objec-

tives.

The horizontal re entry program started in 1993 and by

December 1997 a total of 26 wells were redrilled (16 on J20

block and 10 on O16 block). The reentry procedure basically

consisted in the following: a 30 ft window is cut on the 7 inch

csg, the lower production zone is isolated with a cement plug

and a 6 1/8 inch hole is horizontally drilled into the production

zone. Wells are completed open hole with 4 1/2 inch (0.020

inch) slotted liner across the horizontal section, which has a

length between 1,000 and 1,600 ft.

On reentries three different types of lifting system (Con-

ventional mechanical pumps, progressive cavity pumps and

electrical submersible pumps) are used depending on expected

production rates, which varied between 350 and 1,000 BPD

(Figure 9). Cumulative production for reentries is shown in

Figure 10.

During 1995 a new horizontal well was drilled (CD38) on

O16 block with 2,722 ft of horizontal section into the O14

sand in the Morichal Member. This well has produced up to

2,000 BPD of bitumen with electric submersible pump as the

artificial lift system. A cumulative production of 900 Mbls has

been reached in 2 years (Figure 11). The well casing design is

13 3/8 in. x 9 5/8 in. casing followed by 7 slotted liner in an

open hole, 8 1/2 in.

Based on these excellent preliminary results, during 1996, a

new development scheme started to be tested, horizontal wells

from clusters. The first cluster was I212 with CI223, CI

224 and CI225 wells placed on O13 and O12 sands.

A pilot hole was drilled on CI223 to confirm the geology

of the area, a thick shale was found isolating O13 from O-12

allowing two parallel horizontal wells to be placed on thesame north east direction and one horizontal well placed on

O13 on south west direction.

In 1997 two additional horizontal wells (CI226 and CI

227) were drilled from cluster I204 in block J20 (Figure

12) after investigating on the neighboring well CNX21

using a Carbon-Oxygen log, the movement of the origina

water bitumen contact. All new horizontal wells have the same

design as CD38 except for the length of the horizontal sec-

tion that was shorten to 2,000. With the initial production per

formance results, sensitivities done by simulation have shown

an optimal horizontal section of 3,000 feet for blocks J20 and

O-16 using 600 meters well spacing. Horizontal well perfor-mance is shown in Figure 13.

Productivity index calculations for horizontal wells were

calculated, results indicated that for 3,000 ft horizontal sec-

tion, thickness of 125 feet, kv/kh ratio of 1.0 and 5,500 cps

viscosity, a horizontal well is able to produce 2 to 4 times the

vertical, deviated, slant well production.

Conclusions

Based on results from vertical, deviated, slant, and horizonta

wells it is concluded that there is a huge improvement with

horizontal well technology, issues like well spacing, horizon-

tal section length and lifting systems should be addressed to

improve the horizontal development scheme.


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References

1. Bitor, S.A. Informe Final Actualizacion Plan maestro

1997. Caracas, Noviembre 1997.

2. Bitor, S.A. Plan Maestro 1994. Informe Final. Caracas,

Diciembre 1994.

3. Gonzalez, R. and Briceo, M. Optimizacion de produc-

cion a pozos reentry, area Cerro Negro, Febrero 1996.

4. Joshi, S.D. Horizontal Well Technology, Pennwel Pub-lishing Company,1991.

5. Velazquez, A. Desarrollo de la perforacion horizontal,

area Cerro Negro, VII Congreso Colombiano del petro-

leo, Octubre 1997.

6. Velazquez, A. Perforacion y reperforacion de pozos hor-

izontales, I Congreso de Geologia y Minas, C. Bolivar,

Venezuela,1997.

7. Bolaos, C. Tecnologa de reperforacin horizontal, 6

to Congreso UNITAR. Calgary, 1994.

8. Santos A. and Gonzalez. M. Evaluacin Geolgica del

Area Cerro Negro, Venezuela, Abril de 1996.9. Suarez, S. and Gonzalez, R. Indice de productividad en

pozos horizontales, Venezuela, Junio 1993.

Table 1: Rock and Fluid Properties

O-16 J-20

THICKNESS AVERAGE, (FEET) 275 300

DEPTH, (FEET) 3450 2500

API GRAVITY 7.5 - 8.5 7.5 - 8.5POROSITY, (%) 32.0 - 35.0 32.0 - 35.0

PERMEABILITY, (Darcy) 10.0 - 20.0 10.0 - 20.0INITIAL WATER SATURATION, (%) 18.0 10.0

INITIAL OIL SATURATION,(%) 82.0 90.0VISCOSITY, (Cp) 5500 5500

INITIAL RESERVOIR PRESSURE, (PSIA) 1126 979

RESERVOIR TEMPERATURE, (F) 130 120

RECOVERY FACTOR, (%) 12.0 12.0INITIAL GAS SOLUTION, (SCF/STB) 79.0 79.0


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Figure 1: Geographical Location

Figure 2: Structural Map

FAJA DEL ORINOCO

TOTAL AREA = 54.000 Km2VENEZUELA

N

CERRO NEGRO FIELD

TOTAL AREA = 8.000 Km2

P - 15 P - 16

O-15

O-16

O-17O-18

O-19

N-17N-18

N-19

N-20

N-21N-22

M-18M-19

M-20

M-21

M-22

M-23

L-23

L-18L-19

L-20L-21

K-20K-21

K-22

K-23

J-20

J-21

J-22

J-23

I-20I-21

I-22I-23

I-24

H-23H-22

M-17

K-19

L-22

MPE-1

MPE-3

MPE-4

MPE-1

BITOR

LAGOVEN

JVCO

TOTAL AREA = 180 Km2

STRUCTURAL MAP

MORICHAL MEMBER TOP

-2200

-2100

-220

0

-230

0

-2600

-2800

STRUCTURAL LINE

FAULT

BOUNDARY PARCEL


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Figure 3: Typical Stratigraphic Column (J-20)

Figure 4: Total Production Performance Cerro Negro Bitor Area

2000'

2100'

2200'

2300'

2400

2500'

2600'

EARLYMIOCENE(OFICINAFO

RMATION)

2700'

2800'

MOR

ICHALMEMBER

PILON

MEMBER

O-15

O-14

O-13

O-12

O-11

O-10

O-8

O-7

O-6

O-5

O-4

BRIEFMARINE

DE

LTA

SMOOT

HNESSS

COASTZONE

DELTAZON

E

LOW

JOBO

MEMBER

YABO

MEMBER

F-3,2,1

O-16

O-9

BIM

FREITES

FORMATION


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Figure 5: Vertical well.Typical cumulative production for 150 mts spacing.

Figure 6: Vertical well. Typical cumulative production for 300 mts spacing.

0

100000

200000

300000

400000

500000

600000

YEAR

BLS

1984

1986

1985

1987

1989

1988

1990

1993

1991

1992

1995

1994

1997

1996

I.G.P

O.H.G.P

BOTT

OM

SURF

ACE

150 MTS

CUMULATIVEPROD

UC

TION

0

100000

200000

300000

400000

500000

600000

700000

800000

YEAR

BLS

1984

1986

1985

1987

1989

1988

1990

1993

1991

1992

1995

1994

1997

1996

CUM

ULATIV

EPRODUC

TI O

N

I.G.P

O.H.G.P

BOTTO

M

SURF

ACE

150 MTS


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Figure 7: Slant deviated well. Typical cumulative production.

Figure 8: Vertical deviated and slant wells performance.

0

500000

1000000

1500000

2000000

2500000

BLS

1 32 4 65 7 108 9 1211 1413 15 1716 1918 20

BOTT

OM

SURFAC

E

YEARS

O.H.G.P

O.H.G.P

SURFAC

EBO

TTOM

400 MTS

400MTS

CUMULATIVEPRODUCT

ION

750

600

450

300

150

0

600

450

300

150

0

750

600

450

300

150

01994 1995 1996 1997 1998

1992 1994 1996 1998

1984 1986 1988 1990 1992 1994 1996 1998

VERTICAL WELL, CI - 02

DEVIATED WELL CI - 141

SLANT WELL CI - 157

BPD

BPD

BP

D

Bitumenrate


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Figure 9: Reentry Wells Performance

Figure 10: Reentry Wells Cumulative Production

REENTRY WELL, CC - 13

REENTRY WELL, CD - 01

100

60

40

20

0

80

1994 1995 1996 1997 1998

1994 1995 1996 1997 1998

0

250

500750

1000

1200

1994 1986 1988 1990 1992 1994 1996 1998

1984 1986 1988 1990 1992 1994 1996 1998

100

60

200

80

40

0

500

12001000750

250

W ATERC U (( 100%)

BPD

W ATERC U T(100%)

BPD

VERTICAL

REENTRY

VERTICAL

REENTRY

0

200

400

600

800

1000

1200

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21YEARS

MBD

0

500000

1000000

1500000

2000000

2500000

3000000

QB(B PD) NP( BL S)

O.H

CUMULATIVEPRODUCTION/bLS

CBITUMENRATE


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Figure 11: Horizontal Well Cumulative Production

Figure 12: Cluster I-20-4 Map.

0

200

400

600

800

1000

1200

1400

1600

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21YEARS

MBD

0

500000

1000000

1500000

2000000

2500000

3000000

3500000

4000000

QB(BPD) NP(BLS)

O.H

CUMULATIVEPRODUCT

ION/bLS

CBITUMENRATE

I-21

2000

Mts

CO-5

CO-4

CO-3

CO-2

CI-73

CI-72CI-71

CI-70

CO-1

CO-68

CO-69

CI-67

CI-66

CI-65CI-64

CI-63

CI-62

CI-61

CI-60

CI-59

CI-58

CI-43CI-71

CI-70

CNX-21

CI-220

CI-219

CI-218

CI-204

CI-202

CI-199

CI-221

CI-211

CI-217

CI-206

CI-192

CI-197

CI-222

CI-213

CI-216

CI-208

CI-194

CI-195

CI-106

CI-108

CI-125

CI-105

CI-102

CI-99

CI-122

J-21J-20

I-20-4

O-12/13

sand

2000'


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Figure 13: Horizontal Well Performance

HORIZONTAL WELL, CI - 87

HORIZONTAL WELL, CD - 38

HORIZONTAL WELL, CI - 223

1998199719961995

199819971996

1200

800

400

0

1600

2000

1200

800

400

0

1600

2000

1200

800

400

0

1600

2000

BP

D

BP

D

B PD

Bitumenrate

Documents

1998.176 Orinoco Belt, Cerro Negro Area Horizontal Well Evaluation