POFD by STT Migas Team

Planning Of Further Development

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CONTENTS

Cover........................................................................................................... i

Contents...................................................................................................... ii

CHAPTER I EXECUTIVE SUMMARY................................................ 1

1.1 Plan of further development for layer Y in field X ............................ 1

CHAPTER II GEOLOGICAL FINDINGS ............................................ 4

2.1. Overview............................................................................................ 4

2.2. Formation Evaluation......................................................................... 4

2.3. Stratigraphy........................................................................................ 5

CHAPTER III RESERVOIR DESCRIPTION ...................................... 8

3.1. Reservoir Condition ........................................................................... 8

3.1.1. Initial Condition ................................................................................. 8

3.1.2. Rock Properties .................................................................................. 8

3.1.3. Fluid Characteriztic............................................................................ 8

3.1.4. Drive Mechanism............................................................................... 9

3.2. Estimated Reserve.............................................................................. 9

3.3. Hydrocarbon Reserve......................................................................... 10

3.4. Production Forecast............................................................................ 10

CHAPTER IV FIELD DEVELOPMENT SCENARIOS ...................... 12

4.1. Phases Development .......................................................................... 12

4.2. Development Strategy........................................................................ 12

4.3. Production Optimization .................................................................... 13


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CHAPTER V DRILLING ........................................................................ 14

5.1. Well Allocation .................................................................................. 14

5.2. Well Design........................................................................................ 15

5.3. Existing Well Completion.................................................................. 16

CHAPTER VI FIELD DEVELOPMENT FACILITIES ...................... 18

6.1. Primary Recovery Facilities (Existing Facilities) .............................. 18

6.1.1. “X” Processing Area Facilities .......................................................... 18

6.1.1.1.Receiveing Facilities ....................................................................... 18

6.1.1.2.Export Facilities............................................................................... 21

6.2. Enhanced Recovery Facilities.......................................................... 21

CHAPTER VII PROJECT SCHEDULE................................................ 22

7.1. Projects ............................................................................................ 22

7.2. Project Schedule .............................................................................. 22

CHAPTER VIII PRODUCTION RESULT............................................ 24

8.1. Workover and Reactivation ............................................................. 24

8.2. Pressure Maintenance ...................................................................... 25

8.3. Artificial Lifting............................................................................... 27

CHAPTER IX HSE & COMMUNITY DEVELOPMENT ................... 31

9.1. Pra Construction Phase .................................................................... 31

9.1.1. Identification of Major Hazards and Assessment of Risks.............. 31

9.1.2. Primary Protection ........................................................................... 32

9.1.3. Secondary Protection ....................................................................... 32

9.1.4. Emergency Protection Systems ....................................................... 32

9.2. Construction and Operation Phase................................................... 32

9.2.1. Hydrocarbon Release....................................................................... 33

9.2.2. Fire................................................................................................... 33

9.2.3. Explosion ......................................................................................... 34


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9.2.4. Simulation Drilling and Production................................................. 35

9.2.5. Boat Collision .................................................................................. 35

CHAPTER X ABANDONMENT & SITE RESTORRATION............. 36

CHAPTER XI PROJECT ECONOMICS .............................................. 38

11.1. Economic Calculation...................................................................... 38

11.2. Economic Summary......................................................................... 39

CHAPTER XII CONCLUSION .............................................................. 40

REFFERENCES

ATTACHMENT


1

CHAPTER I

EXECUTIVE SUMMARY

1.1. Plan of further development for Y Layer in X Field

X field is a mature oil field located in Southeast of East Kalimantan and

administratively at Kabupaten Bulungan. “X” Field is in Sub-Basin Tarakan. It was

formed by Sandstone and according to the history of the field gas, was the major

hydrocardon product from this field.

Y layer had been produced since 1960 and had been “shut in” in 2006. It was

shut in because of the reservoir pressure had reach the saturation pressure and the

water cut from this layer almost 100%. But, to develop this layer some problems are

found such as water cut is already high, the last reservoir pressure is below the

saturation pressure, the depth of perforation are below the current water contact zone.

To develop Y layer, the remaining reserve in this layer have to be determined to

make sure that we still have an economic reserve, then the strategy to produce the

remaining reserve : solve the production problems and to optimize the production.

We have to study all of those things until the economic calculation and also the safety

for all operation of this plan of development have to be determined.

a. Technics

To produce the hydrocarbon from Y layer, we have to maintain the current

pressure as steady as possible. Because the reservoir pressure already under the

bubble point pressure, we have to make sure that there is no chance the reservoir

have the pressure drop again. So that, water injection for pressure maintenance is

the main idea to keep the reservoir in steady condition.

Source for this water injection are taken from the produced water from the

production well, fluid from the well at the same layer that already reach 100% of

water cut. For this injection the characteristics of te water injection have to be

nearly the same as the formation water.


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The lifting unit not only install at the 100% water cut well to get the water

for injection. At the production well, it is also necessary to use the liffting unit

due to bottom hole condition.

WorkOver and Reactivation of some wells are also needed to implement in

order to optimize oil rate produced.

Based on the analysis result, B-17 and B-88 are the candidate wells to be

reactivation wells, B-17 is capable of producing oil until the year 2021 and B-88

in year 2018. Estimate cumulative production of oil B-17 is 15,136 bbl and B-88

reached 6,220 bbl.

b. Economic Design

Oil reserve of layer “Y” is 259,300 bbl and has been produced of 56,645

bbl. The remaining reserve of this layer are 23,355 bbl (Proven) and 18,355

(Probable). By the reactivation of both of this wells will increase Recovery

Factor around 8.24% (Probable) and for proven remaining reserve can be

recoverd all. These Recovery Factor can be enhanced by secondary recovery

with pressure maintenance.

c. HSE Control

To promote a safe operation of the installations and to provide the safety

systems needed to protect personnel, environment and assets from threats to

safety caused by the production process, i.e. to prevent a release of hydrocarbons,

hydrocarbon flammable gases and any other abnormal event, and to minimise

their consequence (fire and explosion) should such an event occur.

To achieve these objectives, systems designed to give automatic warning

alarms and provide means to limit the consequences that might occur.

The Safety Concept specify measures to:

• Avoid exposure to potential hazards.

• Minimise the potential (frequency) for hazardous occurrences.


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• Contain and minimise the consequence (fire and explosion) of the hazards.

• Provide means of escape from such hazards.

• Ensure the installation shall be designed to a safe standard.

• Provide a safe working environment for personnel.


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CHAPTER II

GEOLOGICAL FINDINGS

2.1. Overview

The Tarakan Basin encompasses the basinal areas in NE Kalimantan.

Workers in this area usually subdivide the NE Kalimantan basinal areas into four

sub-basins: the Tidung Sub-basin, the Berau Sub-basin, the Tarakan Sub-basin, and

the Muara Sub-basin. The Tarakan Basin is separated from the Kutei Basin by the

Mangkalihat High or Arch. To the west the basin is terminated by the Sekatak-

Berau High of the Central Ranges, the basin hinges on the Semporna High to the

north, and opens eastwards and southeastwards into the Straits of Makassar.

Figure 2.1.

Tarakan Sub-Basin

2.2. Formation Evaluation

Reservoir sandstones in Bunyu Formation, Tarakan and Santul is a zone

containing enough gas potential in the Tarakan Basin. The study was conducted on

drilling wells located in the Tarakan Sub-basin. Stratigraphy that developed in the


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Tarakan Sub-basin prepared by clastic sedimentary rock that is thick at Eocene-

Quaternary, consists of Meliat Formation, Tabul Formation, Santul Formation, and

Tarakan Formation which was deposited on Delta depositional environment. Some

oil and gas field located in the Tarakan Sub-basin generally produced from

sandstone reservoirs contained in the formations mentioned above. Quite a lot of

sandstone layers that develop in each formation with good physical properties and

adequate to serve as a reservoir and has a thick enough layer thickness reaches 25

meters, but not all layers of sandstone are producing hydrocarbons.

Modeling geometry Tabul Formation sandstones in the interval, the Sub-

Basin Tarakan performed with geostatistical approach. Tabul Formation sandstones

have a channel and bar geometry that is deposited on the deposition environment

Tide-Dominated Delta. Channel develops in the direction of WE to NW-SE

direction which is an open basin (basinward). The bar develops in the direction of

tidal, so called Tidal Bar which is a typical form of sediment contained in the

depositional environment Tide-Dominated Delta.

2.3. Stratigraphy

Sandstone layers are deposited repeatedly in several depositional sequences

alternating with the deposition shale, and coal that are characteristic type of

precipitation in the Delta region.

Rifting process by uplifting in the west of sub-basin which is happend in the

Middle Eocene and causing erotion. From this year sedimentation is begin. When

early Oligocene, sedimentation is unconformity to the first cycle. When the rifting

process and uplifting to the east, the transgresive sedimentation becoming into

regresive.


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Figure 2.2.

Process cycle

The regresive sedimentated in transisional-deltaic. The sedimentation

causing from mature fault (Oligocene to early Miocene). Faulting happend when the

next sedimentation (cycle 4), Tarakan fromation sedimentation. Tectonic activity in

the late Pliocene is compressible and procreate strike slip fault. In some place, this

compression normal faults into reserve fault. Tectonic causing uplifting, folding,

faulting in Tarakan Basin, when late Pliocene procreate unconformity.


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In this field consist are some layers and “Y” layer is one of them. In “Y” layer have

some wells (Figure 2.3. well allocation).

Figure 2.3.

Well Allocation Remarks:

B-017

B-047

B-088

B-023

B-074


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CHAPTER III

RESERVOIR DESCRIPTION

3.1. Reservoir Condition

3.1.1. Initial Condition

Field “X” is placed in Sub-Tarakan Basin which has layer “Y” as one of the

layers in this field. The reservoir which allocated in layer “Y” consist of two zones

which are oil and water zone. On April the 26th day in 1958 the reservoir has

characteristic which shown bellow :

Pi : 2090 Psi @ 1458 m TVD

Ti : 243.063 0F

Bgi : 0.00877 rcf/stb

Boi : 1.15838 rb/stb

Rsi : 397 Scf/STB

The condition of reservoir is undersaturated which has bubble point pressure 1421.7

psi in 233.350F. Reservoir has reach the bubble point pressure on 2002 and nowdays

the reservoir have current pressure 1385 psi and current temperature 232.6650F.

3.1.2. Rock Properties

Reservoir in layer “Y” consist of sandstone with the netsand 6 meters. The

porosity of layer “Y” is 22 % and the permeability is about 117.2 mD. Based on

laboratory, reservoir rock tend to water wet which is 25 % initial water saturation.

3.1.3. Fluid characteriztic

The compotition of hydrocarbon in reservoir layer “Y” is defined on

laboratory. Hydrocarbon consist of about 14.25 % natural gas (C1-C4) and dominan

C7+. There also some impurities about 2.27 % (CO2 2.12 % and N2 0.15 %. And by

experiment and simulation data which has some correction give PVT (pressure

volume temperature) data at 232.6650F , such as :


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Bg : 0.0132

Bo : 1.163

SG oil : 0.799

SG gas : 0.856

Oil Viscosity : 0.586

Gas Viscosity : 0.0141

Rs : 268

And by calculation API at 232.6650F is about 31.5213. And according to the API

and the gas oil ratio (231.633), hydrocarbon in layer “Y” is black oil. Black oil

usually has API 15 to 40 and solution gas about 200 up to 700 scf/STB. Black oil or

ordinary black oil also known as dissolved gas oil system constitutes majority of oil

reservoirs. Critical temperature are greater than reservoir temperature. No anomalies

in phase behaviour.

3.1.4. Drive mechanism

Based on reservoir initial pressure which undersaturated there is no gas cap

in the reservoir. Reservoir pressure is higher than bubble point pressure, gas oil ratio

decreasing according to the pressure decreasing and oil produced decreasing

rapidly. Based on that history drive mechanism in layer “Y” is solution gas drive for

understurated reservoir. The wells also produce water. in this case called

combination drive which solution gas drive combine with water drive.

3.2. Estimated Reserve

Determine initial oil in place by volumetric equation, initial oil in place in

layer “Y” is 259.3MBbl. Layer “Y” separate by fault into two blocks, block KA and

PA. The initial oil in place each block are 159.4 MBbl and 99.9 MBbl. Well in

block KA are B-23, B-74 and B-88. And well in block PA are B-17 and B-47. And

free water level up to 1460 m depth (water oil contact).


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Figure 3.1.

Llayer “Y” Structure

3.3. Hydrocarbon Reserve

Hydrocarbon reserve in layer “Y” about 75316.5 Bbl that proven to produce.

And the probable hydrocarbon reserve is 79746.8 Bbl.

3.4. Production Forecast

Based on the oil cut, cumulative production of oil, liquid rate, cumulative

production of liquid and layer performance. Production forecast determine by

decline analysis. And based on the decline analysis and hydrocarbon reserve,

remaining reserve that proven about 18671.5 Bbl. And probable remaining reserve

about 23101.8 Bbl.


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Chart 3.1.

Decline Curve


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CHAPTER IV

FIELD DEVELOPMENT SCENARIOS

4.1. Phases Development

Submission of Plan of Further Development and Authorization for

Expenditure conducted on march 2011.

Procurement activities carried out on October 2011 to January 2012 and

installation of equipment such surface facility for water injection and pipeline

carried out on November 2011 to December 2011. Reactivation of well B-17 and B-

88 will be held on January 2012 (30 days). And is expected in early of February

these wells have started production.

4.2. Development Strategy

Based on the analysis result, B-17 and B-88 are the candidate wells to be

reactivation wells, B-17 is capable of producing oil until the year 2021 and B-88 in

year 2018. Estimate cumulative production of oil B-17 is 15,136 bbl and B-88

reached 6,220 bbl.

Oil reserve of layer “Y” is 259,300 bbl and has been produced of 56,645

bbl. The remaining reserve of this layer are 23,355 bbl (Proven) and 18,355

(Probable). By the reactivation of both of this wells will increase Recovery Factor

around 8.24% (Probable) and for proven remaining reserve can be recoverd all.

These Recovery Factor can be enhanced by secondary recovery with pressure

maintenance.


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4.3. Production Optimization Table 3.1.

B-017 & B-088Oil Cummulative Production B-017 B-088

Year Np (bbl) Np (bbl)

2012 2525.08 2219.05

2013 2258.38 1281.448

2014 1900.016 862.43

2015 1639.56 649.76

2016 1441.63 520.53

2017 1286.07 433.53

2018 1160.58 253.16

2019 1057.18

2020 970.52

2021 896.82

∑ 15,136 6,220


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CHAPTER V

DRILLING

5.1. Well Allocation

The platform is located on offshore.

Here below the description of slot allocation MWP-B.

Figure 5.1.

Platform Layout

NORTH

B‐023

B‐047

B‐088

B‐074

B‐017


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5.2. Well Design

These five wells are directional wells.

Figure 5.2.

Typical well design


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5.3. Existing Well Completion Single completion, cased hole with gravel pack installed.

Figure 5.3.

b-017


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Fugure 5.4.

b-088


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CHAPTER VI

FIELD DEVELOPMENT FACILITIES

6.1. Primary Recovery Facilities (Existing Facilities)

The “X” field is located offshore-onshore at Tarakan basin Kalimantan,

Indonesia. The offshore development includes wellheads and 2(two) central

platform with each 12 “ subsea Oil lines to shore.

The onshore development, as covered in the following process description,

include the initial phase development at the existing “X” field and consists mainly

of:

Receiving facilities for two 12” lines including two pig receivers, a two section

Slug Catcher and inlet header

The export facilities including the metering skid and the pig launcher.

HP/LP flare systems.

Produced water treatment with an oily water flash drum and a water degassing

boot.

Fuel gas system.

Compressed air system including the air compressors, the dryer and the

receivers.

Electrical Power Generation System

6.1.1. “X” Processing Area Facilities

6.1.1.1.Receiving Facilities

The receiving facilities collect the non-treated effluent from the offshore

manifold platform through two 12 “ trunklines at onshore pressure from 210 psi to

140 psi and temperatures from 65°C to 40 0C. Each trunkline has a maximum

capacity of 30 MMscfd.


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Pig Receiver- WDR-12/WDR-13

Each of the two 12 “trunklines has a pig receiver. The pig receiver bypass line

is also connected by a removable spool piece to the corresponding slug cather

inlet.

Slug Catcher - WDR-22/WDR-23

The Slug Catcher is segregated into two sections. Each of the section is

normally fed by one of the 12 “ trunkline and is made of two 18 “ diameter by

27 m sloping pipes (or fingers). On the top of the two pipes a horizontal

header collects the saturated gas to the Flare inlet header. The horizontal

collector on the low end of the two fingers is designed as three phase

separator, removing water (sent under level control to the water treatment),

and crude oil (sent under level control ), . Flows between the fingers of one

section are balanced by the gas equalising lines. If one section is flooded by a

slug, the liquid is partially transferred to the second section by the liquid

equalizing line.The Oil is then sent to second slugcatcher WDR 24 and next

to WDR 25 as a final oil separation.The oil is then pumped by MP 7610/20/30

to export Facilities.

Pumps –MP 7610/20/30

The oil comes from slug catcher is then pumped by three transfer pumps (two

pumps are running, one is standby)

Header.

The inlet header receives the effluent from slug catcher sections

HP/LP Flare System

The HP flare system is made of headers collecting the discharge the HP flare

KO drums, fed by common flare header and subheaders network. The main

sources are the slugcatcher BDV’s, the inlet header PCV’s , . The inlet flow is

segregated from the main flare header to the HP flare drums by symmetrical


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piping arrangemant. Each HP KO drums WDR A/B has capacity of 30

MMscfd and is operating at about 0.4 barg under normal operating conditions

and up to 7 barg at design capacity. The HP flare KO drumsWDR A/B are

designed as at two phase separator removing liquid from the gas in order to

protect the downstream flare from liquid carry over. The liquid is pumped by

MP- WDR A/B to the closed drain system. One HP flare sonic tip is provided

with igniters and pilots.

The LP flare system is made of headers collecting the relieves to the

LP flare KO drums, fed by the main source are the Slugcatcher PSV’s, the

closed drain drums, and the fuel gas system. The LP KO drums WDR C are

designed as at two phase separator. The Liquid is pumped by WDR 5680 A/B

to the closed drum (normally) . The LP flare KO drums WDR 5630 with a

capacity of 30 Mmscfd send gas to the LP flare stack through water seal

drums. The Booster fan provided to get blue light on the top of the LP flare

stack The igniters and the pilot provided on the top.

Water Treatment

The produced water treatment is made of a 1st and 2nd Skimmer tank and a

flotator. This Oily water treatment can handle 20000 BLPD at maximum.

Fuel Gas

The fuel gas system provides clean fuel gas for feeding Turbo Generators.

Instrument / Utility air

TheInstrument air system consists of two compressors, one compressed air

receiver, one instrument air drier unit and one instrument air receiver with it

associated distribution network

Electrical Power Generation System

The Power generation system consist of Two Turbo Generators @ 1.5 MW.


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6.1.1.2.Export Facilities

The export facilities collect the effluent gas and oil from processing facilities .it has

24 “ diameter along 30 Km to PERTAMINA UP V.

Pig Launcher WDR 201.

The pig launcher is provided with the common facilities for gas traps.

Introduction of pigs and pig launching are manual operations.

6.2. Enhanced Recovery Facilities

Since the Oil Production is declining, It is not needed to have a new facilities

therefore It is proposed mainly just for modification of some equipments due to

obsolete part of equipment, safety concern, and to meet with the regulation ( for

Oily water discharged).

Surface Modification of Water Injection Process

Adding one (1) new injection pump and one (1) booster pump

Adding safety device to water injection equipment

PSHH (Pressure Switch High-high)

PSLL (Pressure switch low-low)

LSHH (Level switch high-high)

LSLL (Level switch low-low)

Surface Modification of Oily water treatment Process

Adding chemical injection process


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CHAPTER VII

PROJECT SCHEDULE

7.1. Projects There are Three (3) major projects to be proposed in this Plan Of Development :

1. Surface Facility modification for water injection

2. Surface facility modification for Oily water treatment

3. Workover and wells reactivation

Surface facility modification for water injection is needed since the required

flowrate of injected water will be higher.

Surface facility modification for oilywater treatment is needed to meet with the

environmental rule since the produced water recently does not meet objectives.

Workover and wells reactivation is needed to recover remaining Hydrocarbon that

still economically to produce.

7.2. Project Schedule This schedule will report more detail the progress of :

a. Planning : - Screening study

- Feasibility study

- Conceptual engineering

b. Execution : - Detail Engineering

- Procurement

- Fabrication

- Installation

- Commisioning

- Start-Up

c.Operation : - Put On production


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Table 7.1. Project Schedule

July

2011

Aug

2011

Sept

2011

Oct

2011

Nov

2011

Dec

2011

Jan

2012

Feb

2012

Mar

2012

Apr

2012

May

2012

June

2012

July

2012

Aug

2012

Sept

2012

Oct

2012

Jan

2013

Screening

study July 01 – Oct 25, 2011

Feasibility

study &

Conceptual

engineering

Nov 01 2011 – Feb 27

2011

Detail

engineering

,Procurement

Mar 01 –

April 28

Fabrication &

Installation

May 01 – Sept 29

Commisoning,

start up, Put

On

Production

See note

Note :Commisioning and start up modified water injection and oily water treatment process will be done from Oct 01 –Dec 20 2012.

Workover and wells reactivation will be done on Jan 01 – 31, 2013.


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CHAPTER VIII

PRODUCTION RESULT

This field already have some wells with high water cut and had been temporary

abandon since 2006.To reproduce oil and gas from this filed again, first of all we have to

maintain the reservoir pressure due to the reservoir pressure had reach the saturation

pressure and second, we have to minimize the produce water.

8.1. Workover and Reactivation

There are five wells in the X field that produce from Y layer, almost of these

wells have high water cut and this field have been temporary abandoned since

2006. After six years since the abandonment, it is needed some treatments to

produce the fluis. We have to make the reactivation program and the workover

programs for the wells that we plan as the active production wells.

In the development scenario, B-017 and B-088 are planned to be the

production well. The last condition of these wells, the perforated zone already full

of water. Before producing from these well, we have to clean up the wells to

optimize the production from these wells.

Reactivation and workover programs to do are :

1. Clean up the tubular production by runing scrapper in the wellbore and find

the static fluid level.

2. Shut off the water zone by plugging the well up of the water zone in the well.

3. Add perforation to create the connection again between wellbore and the oil

zone of the reservoir.

4. Recompletion by reinstall the pumping unit in the wellbore and reinstall the

gravel pack to control the sand.


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8.2. Pressure Maintenance

As from the reservoir engineering studies, “Y” layer is a Water Drive

Mechanism system, but the aquifer is not strong enough to support the reservoir

from depletion. The current pressure of the reservoir is 1385 psi, to maintain the

reservoir pressure some of the wells have to be converted to injection wells. So we

can reinject the water produced to these injection wells to maintain the pressure.

The objective of pressure maintenance is to create the pressure drop as steady

as possible, in the other way we have to balance the volume that we produce by

inject the same volume to the reservoir. But, the fluid that will inject to the

reservoir have to be compatible with the formation fluid, in this case we will use

water as the injection fluid. The water that will injected to the reservoir have to be

compatible with the formation water, if not we will have another problems even

our pressure maintenance does not work at all.

Table 8.1

Result Analysis of Water Produce

From Table 8.1, we can say that the produce water from X Field have to be treat if

we want to dispose it to the environment. Or we can use the water produce as

injection water injection for pressure maintenace, not just reduce the cost for water

treatment we also can use it as the water for pressure maintenance. From Table 8.2,

we can say that the composition of injection water and formation are nearly the

same, so they are compatible.


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Table 8.2. Analysis of Injection Water and Water Formation

But, there will be another problem for pressure maintenance that is the produce

water is not enough to used in pressure maintenance. We are gonna need another

source of water that have nearly the same properties like formation water. So that,

we will open another well in Y layer that have the highest water cut and convert it

to be well of water resource that is B-047.

To estimate how much water that we need for water injection we have to

calculate it base on reservoir desription and the field development scenario. As the

safety margins, assume that pressure is tend to deplete again as we open the

reservoir again when we produce the hydrocarbon from this layer for 5 psi. So the

assume reservoir pressure is 1380 psi. (See Table 8.3).

From the Table 8.3, we can forecast how much water that we need to

maintain the pressure at 1380 psi in some rate that we produce from B-017 and B-

088. In this scenario, we will convert B-074 and B-023 to be water injection wells,

as the water produce will not be enough for pressure maintenance, B-047 will asign

as well for water resource.


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8.3. Artificial Lifting

To help the reservoir fluid come up to the surface, installation of artificial

lifting is important. Gas lift installation will not be suitable for this field. Since the

gas produced is not enough and require compressor installation which is very

expensive. Artificial lift that will be work and suitable for this field is electric sub-

mersible pumping. As the location of this field is at the delta environment.

Not only to produce water and oil from production well, we also will use

ESP at the water resource well. Because, the bottom hole pressure was no longer

support to bring fluid to the surface. So that, we will install or reinstall the

pumping unit in every well that we use, except in injection well. As we use the

pumping unit, we can produce the fluid from well in rate that we expected.


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Table 8.3. Calculation for Pressure Maintenance

No. Year Month Qliq (bbl/month)

Cum. Np (bbl) Qo Qg

(scf/month) Qw

(bbl/month) Qinj

(bbl/month) Q to add

(bbl/month)

Qliq (bbl/mo

nth)

Cum. Np (bbl)

Qo (bbl/month)

Qg (scf/month)

Qw (bbl/month)

Qinj (bbl/month)

Q to add (bbl/mont

h)

Qinj total (bbl/mon

th)

Q to add for

both well

(bbl/month)

1 2013 January 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 February 1500.00 40583.76 252.76 1011.04 1247.24 1554.55 307.30 900.00 2985.20 298.20 1192.80 601.80 964.35 362.55 2518.90 669.85 3 March 1499.65 40831.31 247.56 990.22 1252.10 1554.89 302.80 899.13 3253.01 267.81 1071.25 631.31 965.22 333.91 2520.12 636.71 4 April 1499.30 41073.88 242.56 970.25 1256.74 1555.24 298.50 898.25 3496.16 243.15 972.59 655.11 966.10 310.99 2521.34 609.49 5 May 1498.96 41311.64 237.77 951.06 1261.19 1555.59 294.40 897.38 3718.87 222.71 890.83 674.67 966.97 292.29 2522.56 586.69 6 June 1498.61 41544.80 233.16 932.62 1265.45 1555.94 290.48 896.51 3924.35 205.48 821.93 691.03 967.84 276.81 2523.78 567.29 7 July 1498.26 41773.52 228.72 914.88 1269.54 1556.28 286.74 895.64 4115.11 190.76 763.03 704.89 968.71 263.82 2524.99 550.57 8 August 1497.91 41997.97 224.45 897.80 1273.46 1556.63 283.17 894.77 4293.13 178.02 712.08 716.75 969.58 252.82 2526.21 535.99 9 September 1497.57 42218.31 220.34 881.35 1277.23 1556.98 279.75 893.91 4460.02 166.89 667.57 727.01 970.44 243.43 2527.42 523.18

10 October 1497.22 42434.68 216.37 865.49 1280.85 1557.33 276.48 893.04 4617.10 157.08 628.33 735.96 971.31 235.36 2528.64 511.84 11 November 1496.87 42647.23 212.55 850.18 1284.33 1557.67 273.35 892.17 4765.47 148.37 593.48 743.80 972.18 228.37 2529.85 501.72 12 December 1496.52 42856.08 208.85 835.41 1287.67 1558.02 270.35 891.31 4906.05 140.58 562.30 750.73 973.04 222.31 2531.07 492.66 13 2014 January 1496.18 43061.37 205.29 821.14 1290.89 1558.37 267.48 890.44 5039.61 133.56 534.25 756.88 973.91 217.03 2532.28 484.51 14 February 1495.83 43263.20 201.84 807.35 1293.99 1558.72 264.72 889.58 5166.83 127.22 508.87 762.36 974.77 212.41 2533.49 477.13 15 March 1495.48 43461.71 198.50 794.02 1296.98 1559.06 262.08 888.72 5288.28 121.45 485.80 767.27 975.64 208.37 2534.70 470.45 16 April 1495.14 43656.99 195.28 781.11 1299.86 1559.41 259.55 887.85 5404.46 116.18 464.72 771.67 976.50 204.82 2535.91 464.38 17 May 1494.79 43849.14 192.15 768.62 1302.63 1559.76 257.12 886.99 5515.81 111.35 445.40 775.64 977.36 201.72 2537.11 458.84 18 June 1494.44 44038.27 189.13 756.52 1305.31 1560.10 254.79 886.13 5622.72 106.91 427.62 779.23 978.22 198.99 2538.32 453.78 19 July 1494.10 44224.47 186.20 744.79 1307.90 1560.45 252.55 885.27 5725.52 102.80 411.20 782.47 979.08 196.61 2539.53 449.16 20 August 1493.75 44407.82 183.36 733.42 1310.39 1560.80 250.40 884.41 5824.52 99.00 396.00 785.41 979.94 194.52 2540.73 444.92 21 September 1493.40 44588.42 180.60 722.39 1312.80 1561.14 248.34 883.56 5919.98 95.47 381.87 788.09 980.80 192.71 2541.94 441.04 22 October 1493.06 44766.34 177.92 711.69 1315.13 1561.49 246.36 882.70 6012.16 92.18 368.71 790.52 981.65 191.13 2543.14 437.49 23 November 1492.71 44941.67 175.32 701.29 1317.39 1561.84 244.45 881.84 6101.27 89.11 356.42 792.74 982.51 189.77 2544.34 434.22 24 December 1492.36 45114.47 172.80 691.20 1319.56 1562.18 242.62 880.99 6187.50 86.23 344.92 794.76 983.36 188.61 2545.55 431.23 25 2015 January 1492.02 45284.81 170.35 681.39 1321.67 1562.53 240.86 880.13 6271.03 83.53 334.14 796.60 984.22 187.62 2546.75 428.48 26 February 1491.67 45452.78 167.96 671.85 1323.71 1562.87 239.17 879.28 6352.03 81.00 324.00 798.28 985.07 186.79 2547.95 425.96 27 March 1491.33 45618.42 165.64 662.58 1325.68 1563.22 237.54 878.43 6430.65 78.61 314.46 799.81 985.93 186.11 2549.15 423.65 28 April 1490.98 45781.81 163.39 653.56 1327.59 1563.57 235.98 877.57 6507.01 76.36 305.46 801.21 986.78 185.57 2550.34 421.54 29 May 1490.63 45943.01 161.19 644.77 1329.44 1563.91 234.47 876.72 6581.25 74.24 296.95 802.48 987.63 185.14 2551.54 419.62 30 June 1490.29 46102.06 159.06 636.22 1331.23 1564.26 233.03 875.87 6653.47 72.23 288.90 803.65 988.48 184.83 2552.74 417.86 31 July 1489.94 46259.04 156.97 627.90 1332.97 1564.60 231.64 875.02 6723.79 70.32 281.27 804.70 989.33 184.62 2553.93 416.26 32 August 1489.60 46413.98 154.95 619.78 1334.65 1564.95 230.30 874.17 6792.30 68.51 274.03 805.67 990.18 184.51 2555.13 414.81 33 September 1489.25 46566.95 152.97 611.88 1336.28 1565.29 229.01 873.33 6859.09 66.79 267.15 806.54 991.03 184.49 2556.32 413.50 34 October 1488.91 46717.99 151.04 604.17 1337.86 1565.64 227.78 872.48 6924.24 65.15 260.60 807.33 991.87 184.54 2557.51 412.32 35 November 1488.56 46867.15 149.16 596.65 1339.40 1565.99 226.59 871.63 6987.82 63.59 254.36 808.04 992.72 184.68 2558.70 411.26 36 December 1488.21 47014.48 147.33 589.31 1340.89 1566.33 225.44 870.79 7049.92 62.10 248.40 808.69 993.56 184.88 2559.90 410.32 37 2016 January 1487.87 47160.02 145.54 582.15 1342.33 1566.68 224.35 869.94 7110.60 60.68 242.72 809.26 994.41 185.15 2561.09 409.49


29

38 February 1487.52 47303.81 143.79 575.17 1343.73 1567.02 223.29 869.10 7169.93 59.32 237.29 809.78 995.25 185.48 2562.27 408.77 39 March 1487.18 47445.90 142.09 568.34 1345.09 1567.37 222.27 868.25 7227.95 58.02 232.09 810.23 996.10 185.86 2563.46 408.14 40 April 1486.83 47586.32 140.42 561.68 1346.41 1567.71 221.30 867.41 7284.72 56.78 227.11 810.64 996.94 186.30 2564.65 407.60 41 May 1486.49 47725.11 138.79 555.17 1347.70 1568.06 220.36 866.57 7340.31 55.58 222.33 810.99 997.78 186.79 2565.84 407.15 42 June 1486.14 47862.31 137.20 548.81 1348.94 1568.40 219.46 865.73 7394.74 54.44 217.75 811.29 998.62 187.33 2567.02 406.79 43 July 1485.80 47997.96 135.65 542.59 1350.15 1568.75 218.59 864.89 7448.08 53.34 213.35 811.55 999.46 187.91 2568.21 406.50 44 August 1485.45 48132.09 134.13 536.51 1351.33 1569.09 217.76 864.05 7500.36 52.28 209.12 811.77 1000.30 188.53 2569.39 406.29 45 September 1485.11 48264.73 132.64 530.56 1352.47 1569.44 216.96 863.21 7551.62 51.26 205.05 811.95 1001.14 189.19 2570.57 406.15 46 October 1484.77 48395.91 131.19 524.74 1353.58 1569.78 216.20 862.38 7601.91 50.28 201.14 812.09 1001.98 189.88 2571.75 406.08 47 November 1484.42 48525.68 129.76 519.05 1354.66 1570.12 215.47 861.54 7651.25 49.34 197.37 812.20 1002.81 190.61 2572.94 406.08 48 December 1484.08 48654.04 128.37 513.48 1355.71 1570.47 214.76 860.70 7699.68 48.43 193.73 812.27 1003.65 191.38 2574.12 406.14 49 2017 January 1483.73 48781.05 127.01 508.02 1356.73 1570.81 214.09 859.87 7747.24 47.56 190.22 812.31 1004.48 192.17 2575.30 406.26 50 February 1483.39 48906.72 125.67 502.68 1357.72 1571.16 213.44 859.03 7793.95 46.71 186.84 812.33 1005.32 192.99 2576.47 406.43 51 March 1483.04 49031.09 124.36 497.45 1358.68 1571.50 212.82 858.20 7839.84 45.89 183.57 812.31 1006.15 193.84 2577.65 406.66 52 April 1482.70 49154.17 123.08 492.33 1359.62 1571.85 212.23 857.37 7884.94 45.10 180.41 812.27 1006.98 194.72 2578.83 406.94 53 May 1482.36 49276.00 121.83 487.31 1360.53 1572.19 211.66 856.54 7929.28 44.34 177.36 812.20 1007.81 195.62 2580.00 407.28 54 June 1482.01 49396.59 120.60 482.39 1361.41 1572.53 211.12 855.71 7972.88 43.60 174.40 812.11 1008.64 196.54 2581.18 407.66 55 July 1481.67 49515.99 119.39 477.57 1362.28 1572.88 210.60 854.88 8015.77 42.88 171.54 811.99 1009.48 197.48 2582.35 408.08 56 August 1481.33 49634.20 118.21 472.84 1363.11 1573.22 210.11 854.05 8057.96 42.19 168.77 811.86 1010.30 198.45 2583.52 408.56 57 September 1480.98 49751.25 117.05 468.21 1363.93 1573.56 209.63 853.22 8099.48 41.52 166.08 811.70 1011.13 199.43 2584.70 409.07 58 October 1480.64 49867.17 115.92 463.66 1364.72 1573.91 209.19 852.39 8140.35 40.87 163.48 811.52 1011.96 200.44 2585.87 409.62 59 November 1480.29 49981.97 114.80 459.20 1365.49 1574.25 208.76 851.56 8180.59 40.24 160.95 811.33 1012.79 201.46 2587.04 410.22 60 December 1479.95 50095.67 113.71 454.83 1366.24 1574.59 208.35 850.74 8220.21 39.63 158.50 811.11 1013.61 202.50 2588.21 410.85 61 2018 January 1479.61 50208.31 112.63 450.53 1366.97 1574.94 207.96 849.91 8259.24 39.03 156.12 810.88 1014.44 203.56 2589.38 411.52 62 February 1479.26 50319.89 111.58 446.32 1367.68 1575.28 207.60 849.09 8297.70 38.45 153.81 810.63 1015.26 204.63 2590.54 412.22 63 March 1478.92 50430.43 110.55 442.18 1368.38 1575.62 207.25 848.26 8335.59 37.89 151.57 810.37 1016.09 205.71 2591.71 412.96 64 April 1478.58 50539.96 109.53 438.12 1369.05 1575.97 206.92 847.44 8372.94 37.35 149.39 810.10 1016.91 206.81 2592.88 413.73 65 May 1478.24 50648.50 108.53 434.13 1369.70 1576.31 206.61 846.62 8409.75 36.82 147.26 809.80 1017.73 207.93 2594.04 414.54 66 June 1477.89 50756.05 107.55 430.22 1370.34 1576.65 206.31 845.80 8446.05 36.30 145.20 809.50 1018.55 209.05 2595.21 415.37 67 July 1477.55 50862.64 106.59 426.37 1370.96 1577.00 206.04 844.98 8481.85 35.80 143.19 809.18 1019.37 210.19 2596.37 416.23 68 August 1477.21 50968.29 105.65 422.59 1371.56 1577.34 205.78 844.16 8517.16 35.31 141.23 808.85 1020.19 211.34 2597.53 417.12 69 September 1476.86 51073.01 104.72 418.87 1372.15 1577.68 205.54 843.34 8551.99 34.83 139.33 808.51 1021.01 212.50 2598.69 418.04 70 October 1476.52 51176.81 103.81 415.22 1372.72 1578.02 205.31 842.52 8586.36 34.37 137.47 808.15 1021.83 213.68 2599.85 418.98 71 November 1476.18 51279.72 102.91 411.63 1373.27 1578.37 205.10 841.70 8620.27 33.92 135.66 807.79 1022.65 214.86 2601.01 419.96 72 December 1475.84 51381.75 102.03 408.11 1373.81 1578.71 204.90 840.89 8653.75 33.48 133.90 807.41 1023.46 216.05 2602.17 420.95 73 2019 January 1475.49 51482.91 101.16 404.64 1374.33 1579.05 204.72 840.07 8686.80 33.05 132.18 807.03 1024.28 217.25 2603.33 421.97 74 February 1475.15 51583.21 100.31 401.23 1374.84 1579.39 204.55 839.26 8719.42 32.63 130.50 806.63 1025.09 218.46 2604.49 423.01 75 March 1474.81 51682.68 99.47 397.87 1375.34 1579.74 204.39 838.44 8751.64 32.22 128.87 806.23 1025.91 219.68 2605.64 424.08 76 April 1474.47 51781.33 98.64 394.57 1375.82 1580.08 204.25 837.63 8783.45 31.82 127.27 805.81 1026.72 220.91 2606.80 425.16 77 May 1474.13 51879.16 97.83 391.33 1376.29 1580.42 204.13 836.82 8814.88 31.43 125.71 805.39 1027.53 222.14 2607.95 426.27 78 June 1473.78 51976.19 97.03 388.14 1376.75 1580.76 204.01 836.01 8845.93 31.05 124.18 804.96 1028.35 223.39 2609.11 427.40 79 July 1473.44 52072.44 96.25 384.99 1377.19 1581.10 203.91 835.19 8876.60 30.67 122.70 804.52 1029.16 224.64 2610.26 428.55 80 August 1473.10 52167.92 95.48 381.90 1377.62 1581.45 203.82 834.38 8906.91 30.31 121.24 804.07 1029.97 225.89 2611.41 429.72 81 September 1472.76 52262.63 94.71 378.86 1378.04 1581.79 203.74 833.57 8936.87 29.96 119.82 803.62 1030.78 227.16 2612.56 430.90 82 October 1472.42 52356.60 93.97 375.86 1378.45 1582.13 203.68 832.77 8966.48 29.61 118.43 803.16 1031.59 228.43 2613.71 432.10


30

83 November 1472.07 52449.82 93.23 372.91 1378.85 1582.47 203.62 831.96 8995.74 29.27 117.07 802.69 1032.39 229.70 2614.86 433.33 84 December 1471.73 52542.33 92.50 370.01 1379.23 1582.81 203.58 831.15 9024.68 28.94 115.74 802.22 1033.20 230.98 2616.01 434.57 85 2020 January 1471.39 52634.11 91.79 367.15 1379.60 1583.15 203.55 830.34 9053.29 28.61 114.44 801.73 1034.01 232.27 2617.16 435.82 86 February 1471.05 52725.20 91.08 364.33 1379.97 1583.49 203.53 829.54 9081.58 28.29 113.17 801.25 1034.81 233.56 2618.31 437.09 87 March 1470.71 52815.59 90.39 361.56 1380.32 1583.84 203.52 828.73 9109.56 27.98 111.92 800.75 1035.62 234.86 2619.45 438.38 88 April 1470.37 52905.29 89.71 358.82 1380.66 1584.18 203.51 827.93 9137.24 27.68 110.70 800.26 1036.42 236.17 2620.60 439.68 89 May 1470.03 52994.32 89.03 356.13 1380.99 1584.52 203.52 827.13 9164.61 27.38 109.51 799.75 1037.22 237.47 2621.74 441.00 90 June 1469.69 53082.69 88.37 353.48 1381.32 1584.86 203.54 826.33 9191.70 27.08 108.33 799.24 1038.03 238.78 2622.89 442.33 91 July 1469.35 53170.41 87.72 350.86 1381.63 1585.20 203.57 825.52 9218.49 26.80 107.19 798.73 1038.83 240.10 2624.03 443.67 92 August 1469.00 53257.48 87.07 348.29 1381.93 1585.54 203.61 824.72 9245.01 26.52 106.06 798.21 1039.63 241.42 2625.17 445.03 93 September 1468.66 53343.92 86.44 345.75 1382.23 1585.88 203.66 823.92 9271.25 26.24 104.96 797.68 1040.43 242.75 2626.31 446.40 94 October 1468.32 53429.73 85.81 343.25 1382.51 1586.22 203.71 823.12 9297.22 25.97 103.88 797.15 1041.23 244.07 2627.45 447.79 95 November 1467.98 53514.93 85.19 340.78 1382.79 1586.56 203.78 822.33 9322.92 25.71 102.82 796.62 1042.03 245.41 2628.59 449.18 96 December 1467.64 53599.51 84.59 338.35 1383.06 1586.90 203.85 821.53 9348.37 25.45 101.78 796.08 1042.82 246.74 2629.73 450.59 97 2021 January 1467.30 53683.50 83.99 335.95 1383.31 1587.24 203.93 820.73 9373.56 25.19 100.77 795.54 1043.62 248.08 2630.86 452.01 98 February 1466.96 53766.89 83.40 333.58 1383.57 1587.58 204.02 819.93 9398.50 24.94 99.77 794.99 1044.42 249.42 2632.00 453.44 99 March 1466.62 53849.71 82.81 331.25 1383.81 1587.92 204.12 819.14 9423.20 24.70 98.79 794.44 1045.21 250.77 2633.14 454.89

100 April 1466.28 53931.94 82.24 328.95 1384.04 1588.26 204.22 818.34 9447.66 24.46 97.82 793.89 1046.01 252.12 2634.27 456.34 101 May 1465.94 54013.61 81.67 326.68 1384.27 1588.61 204.33 817.55 9471.88 24.22 96.88 793.33 1046.80 253.47 2635.41 457.80 102 June 1465.60 54094.72 81.11 324.44 1384.49 1588.95 204.45 816.76 9495.86 23.99 95.95 792.77 1047.59 254.82 2636.54 459.28 103 July 1465.26 54175.28 80.56 322.23 1384.70 1589.29 204.58 815.97 9519.62 23.76 95.04 792.20 1048.39 256.18 2637.67 460.76 104 August 1464.92 54255.29 80.01 320.05 1384.91 1589.63 204.72 815.17 9543.16 23.54 94.15 791.64 1049.18 257.54 2638.80 462.26 105 September 1464.58 54334.77 79.47 317.90 1385.11 1589.96 204.86 814.38 9566.48 23.32 93.27 791.07 1049.97 258.90 2639.93 463.76 106 October 1464.24 54413.71 78.94 315.78 1385.30 1590.30 205.01 813.59 9589.58 23.10 92.40 790.49 1050.76 260.27 2641.06 465.27 107 November 1463.90 54492.13 78.42 313.68 1385.48 1590.64 205.16 812.80 9612.47 22.89 91.56 789.91 1051.55 261.63 2642.19 466.80 108 December 1463.56 54570.03 77.90 311.61 1385.66 1590.98 205.33 812.02 9635.15 22.68 90.72 789.33 1052.34 263.00 2643.32 468.33 109 2022 January 1463.22 54647.43 77.39 309.57 1385.83 1591.32 205.49 811.23 9657.62 22.48 89.90 788.75 1053.12 264.37 2644.45 469.87 110 February 1462.88 54724.31 76.89 307.56 1385.99 1591.66 205.67 810.44 9679.90 22.27 89.10 788.17 1053.91 265.75 2645.57 471.41 111 March 1462.54 54800.71 76.39 305.57 1386.15 1592.00 205.85 809.65 9701.97 22.08 88.31 787.58 1054.70 267.12 2646.70 472.97 112 April 1462.20 54876.61 75.90 303.60 1386.30 1592.34 206.04 808.87 9723.86 21.88 87.53 786.99 1055.48 268.50 2647.82 474.53 113 May 1461.86 54952.02 75.42 301.66 1386.45 1592.68 206.23 808.08 9745.55 21.69 86.76 786.39 1056.27 269.87 2648.95 476.11 114 June 1461.53 55026.96 74.94 299.75 1386.59 1593.02 206.43 807.30 9767.05 21.50 86.01 785.80 1057.05 271.25 2650.07 477.68 115 July 1461.19 55101.43 74.46 297.86 1386.72 1593.36 206.64 806.52 9788.37 21.32 85.27 785.20 1057.83 272.63 2651.19 479.27 116 August 1460.85 55175.42 74.00 295.99 1386.85 1593.70 206.85 805.73 9809.50 21.13 84.54 784.60 1058.62 274.02 2652.31 480.86 117 September 1460.51 55248.96 73.54 294.14 1386.97 1594.04 207.06 804.95 9830.46 20.96 83.82 784.00 1059.40 275.40 2653.43 482.46 118 October 1460.17 55322.04 73.08 292.32 1387.09 1594.38 207.29 804.17 9851.24 20.78 83.12 783.39 1060.18 276.79 2654.55 484.07 119 November 1459.83 55394.67 72.63 290.52 1387.20 1594.71 207.51 803.39 9871.84 20.61 82.42 782.79 1060.96 278.17 2655.67 485.69 120 December 1459.49 55466.86 72.19 288.74 1387.31 1595.05 207.75 802.61 9892.28 20.43 81.74 782.18 1061.74 279.56 2656.79 487.31


31

CHAPTER IX

HSE & COMMUNITY DEVELOPMENT

Purpose of the HSE & Com-Dev concept is to promote a safe operation of the

installations and to provide the safety systems needed to protect personnel, environment

and assets from threats to safety caused by the production process, i.e. to prevent a

release of hydrocarbons, hydrocarbon flammable gases and any other abnormal event,

and to minimise their consequence (fire and explosion) should such an event occur.

To achieve these objectives, systems designed to give automatic warning alarms

and provide means to limit the consequences that might occur.

The Safety Concept specify measures to:

• Avoid exposure to potential hazards.

• Minimise the potential (frequency) for hazardous occurrences.

• Contain and minimise the consequence (fire and explosion) of the hazards.

• Provide means of escape from such hazards.

• Ensure the installation shall be designed to a safe standard.

• Provide a safe working environment for personnel.

The safety objectives at each engineering phase achieved by the following techniques:

• Identification of major hazards.

• Assessment of risks.

• Definition of the primary protection systems.

• Definition of the secondary protection systems.

• Definition of the emergency protection systems.

9.1. Pra Construction Phase

9.1.1. Identification of major hazards and assessment of risks

A formal HAZID study to identify major hazards and assess risks has

been completed by COMPANY. The HAZID conclusions are that the

hazards related to boat collision, simultaneous operations and dropped

objects must be evaluated and managed Hazard and Operability Studies


32

(HAZOPs) shall be performed during engineering phases, on the basis of the

Phase 1&2 HAZOPs. Project Technical Reviews (PTR) shall be

performed at each project phase.Both HAZOP and PTR shall be performed

by COMPANY and any action arising incorporated into the engineering

documents.

9.1.2. Primary protection

Identification, alarm and control of process potential hazards shall be achieved

by the process control systems.

9.1.3. Secondary protection

Additional protection provided shall be independent of the primary

protection system and may typically include protection against over-pressure

by including PSVs.

The high shut in pressure of the wells has been taken into account in

the phase 1 design, and an additional fixed choke valve is installed on each

wellhead in order to limit the maximum flow together with a full flow PSV to

protect the downstream equipment.

9.1.4. Emergency protection systems

Fire and gas detection, emergency shutdown and blowdown systems are

designed to bring under control hazards which the process control have failed to

detect or prevent.

9.2. Construction and Operation Phase

The following major hazards are considered :

• hydrocarbon release,

• fire,

• explosion,

• simultaneous drilling and production,

• boat collision.


33

9.2.1. Hydrocarbon release

Likelihood and causes : The extent of a release of gas or liquid is largely

dependent of the size of the leak, the pressure inside

the vessel or pipe, and the hydrocarbon inventory.

Causes can be over pressurization, corrosion,

fatigue, shock, collision.

Consequences : The consequences of a hydrocarbon release can be either a fire

(immediate ignition) or an explosion (delayed ignition) which

can expose personnel and/or equipment, and could seriously

impair the plant main safety functions.

Protection : Fixed gas detection will be provided on the platforms with

automatic actions as defined in the relevant section. Electrical

equipment located on the platforms shall be at least suitable to

operate in the relevant Hazardous area for Gas Group IIA

Temperature Class T3 areas. Equipment not suitable to operate in

a Hazardous area shall be located in safe area and provided with

gas detection.

The Remote Telemetry Unit (RTU) shall be certified for Zone 2

and in case of a gas detection isolated after a time delay.

9.2.2. Fire

Likelihood and causes : Fire is defined here as a fire from process facilities

and utilities. Sources of fuel are liquid and gaseous

hydrocarbons and chemicals such as methanol or

corrosion inhibitor. Ignition sources are sparks,

unprotected flames and heat sources.

Consequences : Any pool fire, jet fire or flash fire from a flammable liquid or

gas release could cause the impairment of plant main safety

functions or equipment damage with probable loss of


34

production and injury to any exposed personnel. Heat

radiation from a fire could threaten steel structure and

equipment.

The impairment of the safety critical functions - Emergency

Shutdown and Blowdown valves and systems - as a

consequence of a major fire or explosion are assessed

separately.

Protection : In the present case of unmanned offshore platforms the protection

against fire will be provided by the ESD system, mobile fire

fighting and protection equipment as well as emergency

procedures including the permanent presence in the field of a

stand-by patrol/FiFi boat. Passive fire protection is not required

on structural members because it is assumed that there is no risk

of pool fire and in case of gas fire the ESD and depressurisation

will sufficiently reduce duration and flame lengths to avoid

significant damage in addition to the protection afforded by the

patrol/FiFi boat.

9.2.3. Explosion

Possible causes identified are :

• ignition of a flammable vapour cloud,

• over pressuring of equipment.

Consequences : An explosion could cause equipment damage with possible

loss of production and injury to any exposed personnel. An

explosion may cause impairment of safety critical functions

as well as cause damage to other units in the vicinity.

Protection : Particular attention is given to location and protection of all

ESDVs (incoming and outgoing risers), as well as to the routing

of critical piping such as vent network piping. All decks except

the upper deck, which is used for wireline and possible helicopter


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landing, are as open as possible, composed mainly of grating

panels.

9.2.4. Simultaneous drilling and production

Wells will be killed and at least one packer installed downhole before a

Xmas tree is removed or refitted. The platform will be shutdown before

particularly hazardous operations such as BOP stack lifting.

If a blowout should occur the probability of ignition is high. However

the risk of damage to the sealines is relatively low because the flame will be

vertical with its source probably on the rig floor level. it is assumed that, if the

blowout is at the mezzanine level, the upper deck will be rapidly destroyed

and the flame will become vertical.

9.2.5. Boat collision

Platforms are not designed to resist a cargo ship collision. A patrol/FiFi

boat will be permanently available on the field to detect any abnormal

barge/boat route in the area. Its capacity will also allow to tow/push an

uncontrolled vessel.

Platforms structure is designed to resist a supply/service boat collision on the

boat landing on the basis of the following hypothesis :

• maximum loaded tonnage 500 t

• maximum berthing speed 0.5 m/s

• length x width x draft 41.15 m x 7.60 m x 3 m

• associated wave H x period T 1.5 m x 5 s

Boat landing will be fitted with shock absorbers sized so that horizontal

maximum impact forces will be 100 t at the top of the jacket.


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CHAPTER X

ABANDONMENT & SITE RESTORATION

10.1. Background

In relation to off shore facilities, the united nations convention on the law of the

sea (UNCLOS) 1982 states under article 60(3) that :

“Any installations or structures which are abandoned or disused

shall be removed to ensure safety of navigation, taking into account

any generally accepted international standard established in this regard

by the competent international organization.Such removal shall also

have due regard to fishing the protection of the marine environment

and the rights and duties of other states”.

The Field abandonment plan will include a comparative assessment the purpose

of which will be consider the options for field abandonment in terms of :

Technical feasibility

Safety

Environment

External influences

These five factors will be assessed ranked for each decommissioning option and

a most appropriate approach determined.

a. Wells

Before removing any of the platform facilities it will be necessary to plug

and abandon the well in order to isolate individual productive intervals and

prevent any flow of fluids to the surface.The clearing of any obstruction will

require the cutting of the sub-sea wellheads and conductor casing below the

surface of the seabed.


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b. Process Equipment (Offshore & On-shore)

Process equipment is generally decommissioned by circulating nitrogen

through the process system.The gas strips hydrocarbon that may still be

presenr within the system aftet production operations have ceased

c. Sub-sea Pipe lines

Abandoning the pipelines would require that any areas that may prevent a

snagging risk to fishermen or vessels be covered or removed.

d. On-Shore Terminal

A decision on the decommissioning and removal of the terminal facilities

would be made on whether it can be used for ongoing oil and gas production

from other fields at the time or if any re-use opportunities are available.If a

decision to remove the facility was made, the land would need to returned to

its original state.

Site re-instatement after removal of terminal facilities would include :

A soil (and groundwater) contamination investigation with remdiation as

required.

Landscaping of the area so that it more closely resemble the surrounding

terrain

Re-seeding and re-planting for soil stabilization and habitat restoration.


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CHAPTER XI

PROJECT ECONOMICS

11.1. Economic Calculation

Economic evaluation of layer “Y” based on Production Sharing Contract

(PSC) by BP-MIGAS in accordance with law no.22 of 2001. Distribution of

Equity to be split (ETS) between government and contractor is 85 :15. First

trench petroleum 5%. DMO fee provided by 10% after 5 years.

Further development of layer “Y” the cost as follow :

Investment US$ 293,105

Including are :

• Surface Facility for

water injection and Oily water US$ 189,105

• Work Over for wells

reactivation (B-17 and B-88) US$ 104,000

• Pipeline US$

30,000

Operating Cost US$ 208,219

Capital expenditure (2 wells) US$ 24,000

Non Capital (2wells) US$ 80,000

If the oil price assumption is US$ 70 (fixed for 10 years) with a gross of oil

production amounted to 21,356 bbl. Then the analysis result of “Y” layer

calculation is :

• Government Take

ETS Government US$ 626,506

Tax Income US$ 99,868

DMO after 5 years US$ 7,228

Total Government Take US$ 718,424

•

•


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• Contractor Take

ETS Contractor US$ 234,939

Internal Rate of Return % 45

• Profit Indication

Pay Out Time (POT) Years 1.8

IRR 45 %

11.2. Economic Summary

Gross Production bbl 21.356

Oil Price US$/bbl 70

Gross Revenue MUS$ 1,495

Operating Costs US$ 208,219

Capital Expenditure US$ 24,000

Non Capital US$ 80,000

Total Cost Recovery US$ 605,324

Pay Out Time Years 1.8

Contractor IRR % 45


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CHAPTER XII

CONCLUSION

1. Based on Reservoir & Geological parameter to support Oil be produced, it is

possible this layer can be still treated and economically advantageous.

2. According to the result of economic calculation, reactivation wells is the best

recommendation to develop this layer.

3. By reactivation the wells in layer “Y” the probable recovery is 8.24 % and it is

proven to get recover the well 7.078%.

4. Based on Economic Parameters

ROR=46 %

POT = 1.8 years

government take US$ 718423.54

Contractor take( + cost recovery) US$ 1542219.63

This layer is needed to produce for sure.

5. Based on Safety concern, It is our primarily concept to be first consideration to

develop this layer. The Possibility of accident or incident can be minimized

through very good improvement of safety related to personnel which will

support the economic target

Regarding with factors are considered to develop this field during ten years (10)

such as reservoir, geological, economic parameter and safety concern.

This field has to develop


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ATTACHMENT


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Figure 1 Layer “Y” performance

Figure 2 B-88 Q liquid Vs Gross


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Figure 3

B-88 Oil Cut Vs Cumulative oil production

Figure 4 B-17 Q liquid Vs Gross


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Figure 5 B-17 Oil Cut Vs Cumulative oil production

Figure 6 Pay Out Time


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Figure 7

Rate of Return Qo assume for reactivation of well B-88 and B-17


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Figure 8 GOR and Bo


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Figure 9 Z & Bg

Figure 10 Specific Gravity

Figure 11 Viscousity


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Figure 12 Pressure

POFD by STT Migas Team

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Transcript of POFD by STT Migas Team