berlian east f ield d evelopment p lan prepared by g2: amira binti abdul rasib chiew kwang chian...

1

BERLIAN EASTFIELD DEVELOPMENT PLAN

Prepared by G2:

Amira binti Abdul Rasib

Chiew Kwang Chian

Dexter Brian Anak Nyambang

Mohamad Azir Syazwan bin Sufri

Mohammed Ahmed Omer

Mohd Farid Bin Mohd Toha

Muhammad Syafiq Syahidzat Sabri

Thian Hui Chie

Supervisor: Dr Khaled Abdalla Elraies

2

RESERVOIR ENGINEERING

3

OUTLINE

Introduction Reservoir Data Depletion Strategy Proposed Number of Wells Production Profile Reservoir Management Plan (RMP) EOR Considerations

4

INTRODUCTION – PREVIOUS VOLUMETRIC ESTIMATION

SandSTOIIP (MMstb)

Low Case Base Case High Case

M 2/3 23.4 50.5 89.8

M 7/8 52.4 62.1 73.4

M 9/14 33.9 41.9 58.0

M 15 3.8 5.0 6.4

TOTAL 113.5 159.5 227.6

SandGIIP ( Bscf)

Low Case Base Case High Case

L 16.6 22.9 30.9

M 2/3 2.8 3.2 3.7

TOTAL 19.4 26.1 34.6

5

PVT DATA & INFORMATION PVT data of bottomhole sample from BE-1, M2A sand

Pi >>

Pb >>

• Datum = 1300 m ss• Initial Pressure (Pi) @ datum = 1854 psig• Reservoir Temperature @ datum = 215 °F• Bubble Point Pressure (Pb) = 1332 psig

6

GOR & RS

Rsi = 1400 scf/stb

Pb = 1332 psig

Source: Reservoir Engineering Handbook by T.Ahmed (2001)

7

PVT DATA & INFORMATION Hydrocarbon Analysis on surface fluids:

8

DEPLETION STRATEGY

2 depletion strategies are proposed: Natural depletion drive Water injection depletion drive

Natural Depletion Drive: Recovery factor ≈ 20% of STOIIP Initial production rate = 2000 – 3000 stb/d (from

production test results) Production rates decline (exponentially) @ 38% per year Each well is expected to produce ≈ 3 MMstb Well lifetime ≈ 10 years Abandonment rate = 150 stb/d of gross liquid Water cut < 6% throughout production life

9

DEPLETION STRATEGY

Water Injection Depletion Drive: Natural aquifer does not contribute much Water is injected to support reservoir pressure (not to

flood or displace oil) Recovery factor ≈ 35% of STOIIP Initial production rate = 3000 – 4000 stb/d (from

production test results) Production rates remain constant (plateau) until 40% of

EUR had been produced, then decline @ 40% per year Each well is expected to produce ≈ 5 MMstb Well lifetime ≈ 10 years GOR = Rs throughout production life since Pres > Pb

Maximum injection rate = 4000 stb/d Voidage replacement ratio, VRR = 1.44

10

PROPOSED NUMBER OF WELLS & LOCATIONS – NATURAL DEPLETION

UnitSTOIIP

(MMstb)EUR (20%)

No. of Wells*

Dual Completion

M2/3 50.52 10.10 31

M7/8 62.09 12.42 4

M9/14 41.86 8.37 21

M15 4.98 1.00 0

Total 159.46 31.89 9 2

TOTAL WELLS 11

* Each well will produce ≈ 3 MMstb of oil throughout production life

11

PROPOSED NUMBER OF WELLS & LOCATIONS – NATURAL DEPLETION

11 producers

12

PROPOSED NUMBER OF WELLS & LOCATIONS – WATER INJECTION DEPLETION

UnitSTOIIP

(MMstb)EUR (35%)

No. of Wells*

Dual Completio

n

No. of Injectors**

M2/3 50.52 17.68 31

14

M7/8 62.09 21.73 4

M9/14 41.86 14.65 31

M15 4.98 1.74 0

Total 159.46 55.81 10 2

TOTAL WELLS 12 14

* Each well will produce ≈ 5 MMstb of oil throughout production life

** VRR =1.44 rb/stb; Highest production rate = 39 Mstb/day; Max injection rate = 4000 stb/d

13

PROPOSED NUMBER OF WELLS & LOCATIONS – WATER INJECTION DEPLETION

Injectors12 producers, 14 injectors

14

PRODUCTION PROFILE (MONTHLY) – NATURAL DEPLETION

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 1011050.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

Rate (Mstb/d) Cumulative Production

Month

Prod

uctio

n Ra

te (M

stb/

day)

Cum

ulati

ve P

rodu

ction

(MM

stb)

Rate decreases due to S/D of wells which flows below abandonment rate

15

PRODUCTION PROFILE (YEARLY) – NATURAL DEPLETION

1 2 3 4 5 6 7 8 90.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0


Year

Prod

uctio

n Ra

te (M

stb/

day)

Cum

ulati

ve P

rodu

ction

(MM

stb)

16

PRODUCTION PROFILE (MONTHLY) – WATER INJECTION DEPLETION

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 1011050.00

10.00

20.00

30.00

40.00

50.00

60.00

0.0

10.0

20.0

30.0

40.0

50.0

60.0


Month

Prod

uctio

n Ra

te (M

stb/

day)

Cum

ulati

ve P

rodu

ction

(MM

stb)

Plateau ends after 40% EUR is produced

17

PRODUCTION PROFILE (YEARLY) – WATER INJECTION DEPLETION

1 2 3 4 5 6 7 8 90.00

10.00

20.00

30.00

40.00

50.00

60.00

0.00

10.00

20.00

30.00

40.00

50.00

60.00


Year

Prod

uctio

n Ra

te (M

stb/

day)

Cum

ulati

ve P

rodu

ction

(MM

stb)

18

COMPARISON OF PRODUCTION RATE DECLINATION

1 2 3 4 5 6 7 8 90.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

Natural Depletion Water Injection

Year

Prod

uctio

n Ra

te (M

stb/

day)

19

COMPARISON OF CUMULATIVE PRODUCTION

0 1 2 3 4 5 6 7 8 9 100

10

20

30

40

50

60

Natural Depletion Water Injection

Year

Cum

ulati

ve P

rodu

ction

(MM

stb)

20

RESERVOIR MANAGEMENT PLAN Objectives:

Maximize recoverable oil Maintain reservoir pressure above bubble point (1800 psia) Abide by PETRONAS Procedures and Guidelines for Upstream

Activities (PPGUA)

Operation Strategies: Water Injection to keep P > Pb

VRR = 1.44 and maximum injection rate per well = 4 Mstb/d Gas lift in third year to maintain well rate

Surveillance & Monitoring: Monitor water cut & GOR Utilize S/I for well tests (e.g. interference test, pulse test)

21

ENHANCED OIL RECOVERY (EOR) CONSIDERATIONS

EORTherm

alGas

Chemical

Others

EOR Considerations

Thermal Very costly, suitable for field with oil of high viscosity and low API gravity

Chemical Costly and dependent on many factors: current oil price, water hardness, salinity, temperature etc.

Gas Most suitable compared to other EOR methods. Can consider gas re-injection.

Other Microbial & electromagnetic – new technique, less confidence

22

DRILLING

23

OUTLINE

Rig selection Casing design Bit selection Drilling Fluid design Cementing design

24

RIG SELECTION

• Cost• Rig stability• Water depth offshore

Sea level for Berlian East field = 249.28ft (76m)

Drilling Rigs Water Depth (ft) Average Day Rate (USD)

Jacket Rig 40 – 400 ft $ 40,000

Tender Assisted Rig Anchor length $ 130,000

Jack Up Rig < 350 ft $ 140,000

Semi Submersible Rig 150 – 6000 ft $ 414,000

Drill Ship/ Submersible Rig 1000 – 13000 ft $ 450,000

25

Jack-up Rig• Suitable for shallow depth water • Stable work platform• Lower mobilization cost• Safer and lower risk

26

CASING DESIGN

Casing Casing OD (in) Depth (m-TVDSS)

Conductor 26 “ 80

Surface 13 3/8 “ 400

Intermediate 9 5/8 “ 850

Production 7 “ 1330

27

CASING SETTING DEPTH

28

BIT SELECTION

Casing Casing Size OD (in)

Type of Bit Bit Size (in)

Conductor 26 Rock Bit 30

Surface 13 3/8 Rock Bit 17 ½

Intermediate 9 5/8 PDC Bit 12 ½

Production 7 PDC Bit 8 ½

•PDC bit has most efficient cutting mechanism in sedimentary rock such as sandstone and shale•PDC also have high rate of penetration and long bit life span.

29

DRILLING FLUID DESIGN

Depth, m-TVDSS Mud Design

0-200 Guar Gum Spud Mud

200-1330 High Performance Water Based Mud (HPWBM) + KCL/PHPA additive

• HPWBM performance comparable with Synthetic Based Mud.• Offer environment compliance.• Has been successfully tested on offshore (shallow and depth water). • Cost effective compared to Oil Based Mud.

30

CEMENT DESIGN

Class “G” cement type Additives:

Retarder Fluid loss Dispersant

32

COMPLETION

33

OUTLINE

Preliminary Studies and Well Test Well Locations Completion Matrix Well Completion Options Proposed Well Completion Proposed Perforation Design Proposed Sand Control Design Completion Design Diagram Completion Problem

PRELIMINARY STUDIES AND WELL TEST Field should be developed by initially targeting;

M formation > L formation Sand production were traced in 6-well High permeability; 118-900md Geologically younger Tertiary sedimentary

formations; little cementation material between sand grains

WELL LOCATIONS

12 producers, 14 injectors

COMPLETION MATRIX

UnitSTOIIP (MMst

b)

OIL PRODUCER WELL

W1 W2 W3 W4 W5 W6 W7 W8 W9 W10

W11

W12

M2/3 50.52

M7/8 62.09M9/1

4 41.86

M15 4.98

WELL COMPLETION OPTIONS

COMPLETION PARAMETERS OPTIONS

Tubing size Range from 2-3/8” to 4-1/2”

Type of completion Single or Dual String

Tubing material Carbon steel, Low Alloy Steel or Corrosion Resistance Alloy (CRA)

Perforation Tubing Conveyed Perforating/ Wireline Conveyed Perforating

Artificial Lift ESP or Gas Lift

Sand Control Sand Screen or Gravel Pack

WELL COMPLETION SELECTION COMPLETION PARAMETERS SELECTION COMMENT

Well Orientation Vertical Low risk

Tubing size 2-7/8”, 6.5 PPF, J-55

Based on Nodal Analysis, Shallow Depth

Tubing materialCorrosion Resistance Alloy (CRA)

Due to high carbon dioxide, CO2

Perforation TCP 200psi overbalance (6 shots/foot, 60⁰ degree)

Sand Control Sand Screen Sand production traced

Artificial Lift Gas LiftDepending on production requirements at designated depth

Type of completion

Single and Dual String

For well more than 2 drainage points, used dual strings

PERFORATION DESIGN

Parameters Selection Justification

Perforation Density (spf) 6

Low flow rate of single perforation, low fluid velocity, low sand

Phase 60 provide more efficient flow characteristics

Charge Type DPProvide mechanical stability

Penetration Depth 10-30ft

Perforation Diameter

8-10 times size of the particle Best effectiveness

Completion FluidNitrogen and Clear Solid Brine

Cheap, avoid contaminants precipitation and crystallizationDensity: 7.5 – 10ppg

SAND CONTROL DESIGN CRITERIA

Gravel Packing

Parameters Criteria

Size US Mesh 12/20 – 40/70 (5 times mean diameter of formation sand)

Sphericity ≥0.6

Roundness ≥0.6

Class Natural or Manmade

Screen

Gravel Size (US Mesh) Gravel Size (in.) Screen Gauge (in.)

12/20 0.0660-0.0330 0.020

16/30 0.0470-0.0230 0.016

20/40 0.0330-0.0165 0.012

40/60 0.0165-0.0098 0.008

COMPLETION SCHEMATIC DIAGRAM(SINGLE STRING)

Wellhead1. Assemble 1

1. 2-7/8” Flow Coupling2. 2-7/8” TR-SCSSSV3. 2-7/8” Flow Coupling

2. 2-7/8” GLM (Dummy Valve)3. 2-7/8” CIV Mandrel4. 2-7/8” PDG Mandrel5. 2-7/8” Sliding Sleeve6. 2-7/8” XN Nipple7. Single Swell Packer8. EOT

1

2

34

567

8

COMPLETION SCHEMATIC DIAGRAM(DUAL STRING)



2. XN-Nipple3. 2-7/8” GLM (Dummy Valve)4. Assemble 2

1. Flow Coupling2. XD-SSD3. Flow Coupling

5. Dual Swell Packer6. Assemble 37. Single Swell Packer8. XN Nipple9. EOT

12

3

45

6

78

9

COMPLETION SCHEMATIC DIAGRAM(INJECTION WELL)



2. X-Nipple3. XD-SSD4. Single HYD Packer5. X-Nipple6. EOT

1

2

34

5

6

COMPLETION PROBLEMSPRODUCTION

PROBLEM EFFECT MITIGATION PLAN

Wax deposition • Flow assurance issue• Surface/downhole

equipment blockage

• Thermodynamic or chemical injection approach

• Maintenance pigging operation

Scale formation • Wellbore and flowline blockage

• Reduction in production rate

• Fluid filtration • Scale inhibitor• Acid treatment

Emulsion formation

• Cause formation damage• Well productivity decrease

• Use surfactant; reduce surface and IFT of fluids

High CO2 content

• Facilities corrosion (valve, pipeline)

• Use corrosion inhibitor, CRA

Sand Production • Erosion at surface and downhole equipment

• Collapse of the formation

• Sand screening, minimum entry hole diameter, high shot density

45

FACILITIES

46

OUTLINE

Design Philosophy Proposed Philosophy Proposed Development Plan Screening Process Development Plan Selection

47

INTRODUCTION

Provide information on the surface facilities

based on the subsurface production in order to

develop Berlian East Field

Design basis

Environment

Sea Floor Site

Production

Processes

Flexibility

48

26 wells [12 producers and 14 water injectors]

tie-in with 2 mother platforms (2 SWP for each mother platform)

Full well stream the crude oil to Berlian complex via pipelines

DESIGN PHILOSOPHY

49

Unmanned facilities

Minimum maintenance

Meet simultaneous production and drilling

operations and workover requirements.

Remote well testing on monthly basis.

Maximise remote monitoring and control

capability from supply terminal at pekan.

Over 9 years of operating life and 30 years of

design life.

PROPOSED PHILOSOPHY

50

PROPOSED DEVELOPMENT PLAN

Option A – Satellite Wellhead Platform:

A1) Satellite wellhead platform, tie-in to

mother platform and full well stream

pipeline to Berlian complex.

A2) Connecting the Satellite Wellhead

platform to a FPSO.

A3) Connecting the Satellite Wellhead

platform to a MOPU.

51

Option B – Subsea Wellhead Platform:

B1) Subsea wellhead platform, tie-in to

mother platform with full well stream

pipeline to Berlian Complex.

B2) Connecting the Subsea wellhead

platform to a FPSO

B3) Connecting the Subsea wellhead

platform to a MOPU

52

Option C – Central Processing Platform:

C1) Central processing platform and tie-in

with Berlian export oil pipeline to

Pekan Crude Oil Terminal

C2) Central processing platform and

pipeline to Pekan Crude Oil Terminal.

53

SCREENING PROCESS

FPSO eliminated;

High cost – rental

Major modification

Bad weather condition

Subsea Wellhead Platform eliminated;

Only for deepwater operation

High cost

54

CPP eliminated;

High cost – start-up, operating &

abandonment

Require manpower

Complexity operation

MOPU

Bad weather – same as FPSO

55

DEVELOPMENT PLAN SELECTION

We opted the Satellite wellhead platform, tie-

in to mother platform and full well stream

pipeline to Berlian complex (Option A1)

Reason;

Low CAPEX and OPEX

Unmanned operation

Existing facilities utilized

56

Substructure 6 pile-steel Riser (seabed to platform) Boat landing bay Pipeline

Top structure Crane Helipad Well servicing equipment Main production facilities;

Wellhead Three-phase separator Gas injector Electrical / lighting Flare boom

Safety equipment

57

Schematic diagram of Berlian East conceptual facility design

58Schematic diagram for each well location in Berlian East field

59

ECONOMICS

60

FISCAL TERM FOR PSC 1997

Terms Details

Contract area EPCP Block

Contract duration Max 22 years

Production period 15 years

Royalty rate 10%

Cost oil ceiling rate Oil Gas

50%60%

Profit oil share (PETRONAS: Contractor) 60:40

PSC base price US$40/bbl escalated 3% p.a. from current year

Export duty (ED) rate 10% of profit oil exported

Research cess 0.5% oil/gas entitlement

Abandonment cess 5 USD Mill

Petroleum tax rate 38%

Oil supplemental payment 60% (PSC oil price – base price) cont. PO – export duty

Fixed structure 10% per year (10 years)

61

Base case

Reference year

First oil Expected to be in 2016

Production period 10 years

Decommissioning year

Exactly after 10 years of production period (2013)

Cash flow model Assumed to be in the Money of the Day (MOD) term

Base oil price US$40/bbl escalated 3% p.a. from current year

Operating cost (OPEX) 4% of cum. CAPEX per annum (fixed OPEX) plus US$3.50/bbl (variable OPEX)

Hurdle rate for IRR 15%

Discount rate 15%

ECONOMIC ASSUMPTIONS

62

Production facilities Option A1: Satellite wellhead platform, tie –in to mother platform and full stream pipeline to Berlian complex

Production case • 11 producer wells•14 injector wells• RF of 20% = 5 MMSTB

NPV @ 15%

IRR 25%

CAPEX USD 393 Million

OPEX USD 303 Million

Decommisioning USD 119 Million

Payback period 2 years

Economic life 10 years

DEVELOPMENT OPTION

63

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

-200

-100

0

100

200

300

400

Net Cash Flow Diagram

Year

USD

Mill.

64 Payback period = 2.3 years after first oil @ year 5

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

-400

-300

-200

-100

0

100

200

Cum Net Cash Flow Diagram

Year

USD

Mill.

65

REVENUE SPILT

Summary of Economic Indicators

Contrac.Petronas Govern. Capex Opex Total Project

PV Cash Surplus @ 15% 89 329 611 277 139 1445 379

Internal Rate of Return (IRR) 25% 46.8%

Payout Time 2 Years

USD Mill.

66

SENSITIVITY ANALYSIS

67

HSE & WELL ABANDONMENT

68

HEALTH, SAFETY AND ENVIRONMENT

Objective: The design of the Berlian East facilities shall be

in accordance with the relevant PETRONAS Technical Standards (PTS).

to ensure that the facilities are operated in a safe and responsible manner.

Identified, evaluate and control all potential hazards that could cause a major accident

69

HSE MANAGEMENT SYSTEM (HSE-MS)

70

APPROACHES:

Safety & Risk Management Occupational Health Management Quality Management Environmental Impact Assessment

71

WELL ABANDONMENT

To isolate the reserves remaining in the reservoir

No fluid movement

72

ABANDONMENT DESIGN

1. Isolate perforation intervals

2. Isolate tubing & casing annulus

3. Isolate non-cemented annulus

4. Cut and pull the casing5. Plug surface cement

Well abandonment planning is considered during well construction planning.

73

CONCLUSION

74

CONCLUSION Reservoir Drilling

12 producer wells 14 injection wells

Completion• Internal gravel pack with wire wrapped screen

(WWS)• Tubing: 2-7/8”, 6.5 PPF, J-55 (CRA)

Facilities• 4 satellite wellhead, 2 mother platforms• Tie-in to Berlian CPP

75

Economics• Payback period=??

o HSE & Well Abandonment• Personnel, equipment & facilities comply to HSE

policy

76

THANK YOU

77

BACK UP

78

DATA AVAILABLE – FORMATION WATER Sample taken from BE-3, M2/3 sand

Appearance – Light blackish Total dissolved solids – 30.13 g/L Specific gravity @ 750 °F – 1.023 pH @ 22 °C – 8.14

Formation Water Analysis:

79

DATA AVAILABLE – WELL TEST RESULTS

80

DATA AVAILABLE – WELL TEST RESULTS

81

SUMMARY OF RESERVOIR FLUID

Sampling datum = 1300 m ss Reservoir Pressure @ datum = 1854 psig Reservoir Temperature @ datum = 215 °F Bubble Point Pressure, Pb = 1332 psig

Oil FVF, Bo = 1.4372 rb/stb

Initial Solution Gas Ratio, Rsi = 1400 scf/stb

82

PROPOSED WELL LOCATIONS – NATURAL DEPLETION

83


84


85


86

PROPOSED WELL LOCATIONS – WATER INJECTION DEPLETION

Injectors

87


Injectors

88


Injectors

89


Injectors

90

SAFETY AND RISK MANAGEMENT

All personnel shall show leadership and commitment towards the HSE requirements.

HSE Hold Points shall be held to ensure that all the HSE activities requirements stipulated in the PETRONAS HSE-MS shall be carried out.

All identified concerned risk on the chemicals should be listed in the Material Safety Data Sheet (MSDS) and operational safety in the Hazards Effect Register (HER) .

91

OCCUPATIONAL HEALTH MANAGEMENT

Guidelines and procedures shall be establish and implemented: Job Safety Analysis (JSA), Permit to Work (PTW), Material Safety Data Sheet (MSDS) for

consumables. Hazards Effect Registers (HER) where operation

involves heavy machineries. Offshore Safety Passport system for all

personnel - to ensure the fitness of the personnel working offshore

92

QUALITY MANAGEMENT

Objective: Provide assurance and maintain control in

ensuring that all services and products resulting from its activities are in accordance with the specified requirements.

Demonstrate that any non-compliance has been appropriately endorsed, documented and resolved/close-out.

Ensure that records and hand-over documentation are properly planned, compiled and completed during work.

93

ENVIRONMENTAL MANAGEMENT

Environment Impact Assessment (EIA) Approval seeking from Department of

Environment prior to project start. comprise three major steps; Preliminary

Assessment, Detailed Assessment and EIA Review.

be prepared in parallel with detail technical studies of the overall project feasibility in order to review options and to eliminate or refine alternatives regarding to environment effects.

Waste Management pollution and waste management during

installing, hook up and commissioning, drilling and production activities.

94

POTENTIAL DRILLING PROBLEM

Mechanical Pipe Sticking Loss of Circulation Hole Deviation Hydrogen Sulfide- Bearing Zones and Shallow

Gas

berlian east f ield d evelopment p lan prepared by g2: amira binti abdul rasib chiew kwang chian...

Documents