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Transcript of POFD by STT Migas Team
Planning Of Further Development
i
Planning Of Further Development
ii
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
Planning Of Further Development
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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
Planning Of Further Development
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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.
Planning Of Further Development
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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
Planning Of Further Development
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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
Planning Of Further Development
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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
Planning Of Further Development
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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
Planning Of Further Development
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(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.
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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
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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