RESERVOIR SIMULATION PROJECT

Ajwejara Field, Indonesia

Ajwejara is a giant oil field located in in East Kalimantan, Indonesia, in the central part of the Tertiary
Kutei basin (Figure 1). The structure of the field is a simple anticline, 10 km long and 4 km wide, with
a main east-west fault dividing a North and a South areas, areal closure is 35 km², see the structural
cross section shown on Figure 2. Vertical closure increases with depth through the hydrocarbon-
bearing section.

The anticline feature was found by seismic work in 1973, the discovery well being drilled in April 1974.

Figure 1. Location map

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The geology is complex, the field comprises more than 500 hydrocarbon accumulations, stacked
between 300 m and 4000 m subsea. Most of them are oil bearing with a gas cap.

Figure 2. Structural cross section of the field

Vertically, the field has been sub-divided in a Shallow Zone, grouping the accumulations from 300 to
1500 mSS. A Main Zone between 1500 and 3000 mSS. And a Deep Zone with the accumulations
below 3000 mSS. Around 300 oil accumulations are found in the shallow and main zones, while the
200 gas accumulations lie mostly in the deep zone (Figure 3).

The reservoirs are of excellent characteristics, with permeabilities ranging from 10 to 2000 mD,
porosities in the vicinities of 25% and the connate water saturations around 22%. Within a given
reservoir, the vertical permeability is of the same order as the horizontal permeability.

Most of the oil accumulations consist of a large column typically with more than 100 m of saturated oil
underlying a gas-cap, the relative size of which is very variable. The structural dip ranges from 5 to
12°, down to the aquifers generally connected in the western and eastern sectors. The aquifers are
generally very strong in the shallow zone, and less strong in the main and deep zones.

The initial pressure regime is hydrostatic, while the temperature gradient is 0.03 °C/m. The oil density
varies between 31 and 34°API from the shallow to the main zone. The initial oil formation volume
factor is 1.1 – 1.4 v/v, dissolved gas-to-oil ratio is 50 – 100 v/v, oil viscosity 0.6 – 1.0 cP and the gas
formation volume factor range from 0.005 – 0.01 vres/vsurface.

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 Figure 3. Vertical zones on Ajwejara field – structural cross section of the field.

II. Geology of Ajwejara Field

2.1 Geological Settings

Ajwejara field is in the swampy distributary area in East Kalimantan, in the central of Kutei basin. The
depositional environments can be identified as channel fills and tidal bars.

Figure 4. Location map, Kutei basin.

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The distribution of the sand during the middle and late Miocene indicates that the position of the
Miocene delta coincides with the recent delta of Mahakam River. Moreover the presence of the
maximum thickness of the upper and middle Miocene fluvial facies in the axis of the present delta
shows that the distributaries have not significantly changed position since that time.

Consequently, it was a "Proto" Mahakam river located at the same place as the current Mahakam
river which deposited the producing zones of Ajwejara field.

2.3 Ajwejara Structure

In the delta and offshore the same north–northeast to south–southwest structural deformation is
completely obscured by the rapid recent sedimentation, but is clearly seen on the interpretation of the
seismic data.

It is thought that these trends are the result of the eastward sliding of the thick sedimentary cover
which is made up mostly of shale. This folding was accentuated by shale diapirism in the center of the
anticlines which has led in some places, to localized thrusting on the flanks of the structures. This
motion toward the depocenter has abutted against a north to south oriented basement high in the
Ajwejara area resulting in crumpling, parallel with the high of the shallow more clastic – rich
sediments.

Ajwejara is the southern extension of the Badak – Nilam trend which is parallel with the Attaka –
Bekapai trend (Figure 6).

The Ajwejara Structure was first mapped after a seismic survey in 1973 (Figure 7). This survey, rather
than using the river courses to shoot seismic, avoided the water whenever possible.

Drilling data have confirmed the anticlinal structure defined by seismic data in 1973. The anticline has
an average dip of 10° on the east flank and 8° on the west flank where there is a spill point toward the
northwest (Figure 7). Development wells have shown that dips along the structural axis are smaller
than shown on the seismic data and the area of structural closure at the depth of the main
hydrocarbon levels is 40 km². The vertical closure increases with depth, from 100 m at a depth of 850
m to more than 300 m below 2200 m depth. The area of structural closure also varies partly in relation
to the increasing vertical closure but also due to shifts in the top of the structure and changes in its
length.

A major fault cuts the field into two major parts. This normal fault is now defined in four wells and is
oriented almost perpendicular to the axis with a dip of 70° southward and a throw of 80 m in the main
reservoir interval. The throw decreases with depth from 100 m at 1200 m depth to 70 m at 2400 m
depth, and the fault appears not to cut the zones below 3000 m but this has not been confirmed by
drilling data. It is not known if the fault extends beyond the vicinity of the structure. This fault was not
an important factor in the accumulation of the hydrocarbons. It occurred after the initial
migration of hydrocarbons and presently acts as a seal.

The fault pattern of the whole field shows only four faults in the southern compartment and none in
the northern. Another major structural feature, which has a strong effect on the distribution of
hydrocarbons within the field, is the displacement of the progressively higher stratigraphic horizons on
the top of the anticline (some 3 km) southward along the axis of the anticline. The top moves into the
southern compartment. This displacement of the top may be due to the minor faults.

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All the reservoirs are at hydrostatic pressure so an equilibrium was attained after faulting, and there is
no noticeable diminution of the gas caps in the southern downfaulted compartment nor gas-cap
extension in the north.

Figure 4. Structural map of horizon 4 of the Mahakam delta area showing north – northeast – south –
southwest trending axis.

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 Figure 5. Isobath map of Ajwejara structure based on well data. Thickness corresponds to the
reservoirs in the Main Zone

III. Reservoir Distribution and Characteristics

Well to well correlations are based on the continuity of the lignite and coal beds. More than 70 marker
beds have been defined between the depths of 450 m and 2900 m and most are lignite coal beds or
organic-rich shale. They provide a helpful framework for reservoir correlations.

The reservoirs producing hydrocarbons are often complex bodies made of bar and/or channel
sandstones. As elementary units of deltaic sequences the reservoirs of channel or bar type have
different reservoir characters. Channels create thick and good quality reservoirs of elongated and
frequently sinuous form. Bars are thinner and more shaly, except at the top of the sequences, and
although generally of wide areal extent, they have limits which are more related to the reservoir cut-off
value rather than an identifiable sedimentary boundary. Such elementary units often coalesce
vertically or laterally and this results in reservoirs of complex geometry and varied quality.

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The vertical distribution of the reservoir shows, from top to bottom, a succession of hydrocarbon-
bearing and water-bearing sandstones as if several "pools" composed of different sandstones were
superposed one over the other (Figure 8). In each of these pools, the uppermost reservoirs have the
largest gas caps and the lowest sands of each unit are water bearing. Historically, these units have
been defined one after the other during development drilling. These sandstones form individual pay
zones which have different horizontal extension.

Figure 6. Schematic north to south cross section of the northern compartment and a Ajwejara cross
section shows the major fault and the reservoir distribution.

The medium channel located on the western flank erodes the medium bar and is thought to
communicate with the lower bar, but this has not been verified by well control. Fluid content and
pressure measurements have confirmed the good connection between the upper and middle bar in
the northern compartment of the field where the erosion by the upper channel links the two
sandstones.

Such analysis are necessary to understand the complex geometry of the reservoir and these models
are then used for the location of new development wells, reserve calculations and as data base for
reservoir simulation studies.

IV. Reservoir Characteristics – Facies

Three main type of reservoirs were described from initial core studies and log responses were
calibrated on these cores.

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Type I
The best quality reservoirs are composed of clean sand with shale confined to a small amount of
dispersed clay and few shaly laminations. These sandstones have high porosities and good horizontal
and vertical permeability. Although the vertical permeability is lower than the horizontal, they are of
the same order of magnitud. Because there is a fairly good correlation between horizontal
permeability and porosity, the permeability can be easily estimated from the porosity determined from
the logs. This reservoir quality is found mainly in the lower and middle part of the channel fills and at
the top of the bars when they are well developed.

Type II
Intermediate quality reservoirs are made of shaly sandstones where the porosity is partly reduced by
dispersed clay and many shale laminations. The horizontal permeability is still high but the vertical
permeability is reduced by the laminations, about 10% of horizontal permeability. This kind of facies
appears near the top and the edges of the channel-fill sequences and forms the main part of the bars.

Type III
The poorest category of reservoirs are the very shaly sandstones with low porosities. There are in fact
two types: (III.1) where shaliness is mainly due to dispersed clay mixed with the sand by bioturbation,
and (III.2) where bulk shaliness seen on gamma-ray logs is due to thin intercalations of fine shaly
sands and shale levels. Bioturbated levels are found specially at the top of the channel-fills when the
vegetation of the delta plain progrades over the channel; they have very low vertical and horizontal
permeabilities.

These different qualitis of reservoirs are called I, II and III type, and for each of them, the cut-off on
porosity and shale content have been defined, so the tyope of reservoir could be deduced from logs.
Table 1 shows the shale content. If the cut-off on the shale content is constant, cut-off on porosity is
related to depth (Table 2).

Reservoir Type I II III

Shaliness cut off (%) < 25 < 40 < 55

Table 1. Shaliness cut-off used for the different reservoir types.

Reservoir Type
Interval depth Maximum
(m) porosity (%) I II III

above 800 38 24 20 14
800 – 1200 34 22 18 12
1200 – 1800 30 18 16 10
1800 – 2200 26 18 14 8
2200 – 2800 22 16 12 6

Table 2. Porosity cut-off for the different reservoir types at different depths.

The reservoir that we will study is located in the Main Zone of the Ajwejara field, in the
northeastern compartment between 1500 and 3000 mSS. The simulation study will be
developed in the "reservoir B" shown on Figure 10.

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The "reservoir B" characteristics are shown on Table 3.

Figure 7. Vertical cross section showing rows of producers on the Main Zone.

Reservoir OOIP (MMbbl)  (%) Swi (%) WOC (mSS) GOC (mSS) Mean NTG
A 24.6 22 19 1956 1836
B 106.3 23 20 2090 1908 0.728
C 36.8 25 15 2160 1976

Table 3. Reservoir Data for Ajwejara Main Zone.

V. Reservoir B – Main Zone

As mentioned before, the simulation study will be performed on reservoir B in the Main Zone.

5.1. Well's Correlation

Based on well's correlation, reservoir B is located between markers m1 and M1-1 (Figure 11). In
general m1 marker consists of either organic shale or shale and M1-5 marker consists of coal.
Maximum thickness reaches 49.5 m (P-10) suggesting that this reservoir should have comprised
more than one single channel. It was previously mapped as a single reservoir.

The reservoir B is split into two reservoirs:

• Reservoir Upper : between m1 and M1-1

• Reservoir Lower : between M1-1 and M1-5

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Figure 8. Well's correlation

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V. Reservoir Simulation Model

In summary, our reservoir model will correspond to the Reservoir B of the Main Field Zone, stacked
at 1877 mSS, trapped in channel-sand and sand-bar reservoirs deposited in a fluvio-deltaic
environment of Miocene age.

Reservoir B has good petrophysical characteristics, with horizontal permeabilities from 80 to 2000
mD, porosities in the vicinities of 25% and the connate water saturations around 22%. Within this
reservoir, the kv/kh ratio is the 10%.

This reservoir consist of saturated oil underlying a gas-cap. The structural dip ranges from 5 to 10°,
down to the aquifers generally connected in the western and eastern sectors. The aquifers are rather
strong. The initial pressure regime is hydrostatic, while the temperature gradient is 0.03 °C/m. The
bubble pressure is 2805 psia.

The oil density at surface conditions is 32.72 °API. At bubble point, oil formation volume factor is 1.32
v/v, dissolved gas to oil ratio is 0.53 v/v, oil viscosity 0.61 cP, and the gas formation volume factor is
0.98 v/v.

Based on the characteristics described previously, a reservoir simulation model was designed to
investigate the production capacity of this reservoir.

5.1. Geometry

In this study, the reservoir grid is made of 50 x 113 x 27 = 152550 cells. Only 5369 cells are active.
The typical dimensions of a grid cell is DX = DY = 100 m and DZ = 5 m (Figure 9).

Figure 9. Grid representing the geological model

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Vertically, the grid is split into 3 zones to better represent the stratigraphy of the reservoir. The upper
part of the reservoir is modeled by Layers 1 to 17 and the lower part by Layer 19 to 23. The partial
connection between them is insured by Layer 18. Two rock types (Bar and Channel) have been
defined within the reservoir model.

In this model the channel facies represents 95 % of the initial oil in place.

The porosity distribution is based on two variograms, one for each facies (bar and channel) and
respects the well porosity. Different options of variogram resolution and distribution around the wells
have been tested. The variogram of 2500x1500 and a spherical distribution around the wells have
been retained.

6.2. Aquifers

The main aquifer influx (aquifer 1, Figure 10) is supposed to have a north – south direction, the same
as the facies creation direction. Three other analytical aquifers were modelled for pressure
maintenance reasons.

Aquifers are modelled using Carter Tracy analytical aquifers, which is a simplified approximation to a
fully transient model. The method uses a table that supplies a constant terminal rate influence
function. Although the theory has been developed for a radially symmetric reservoir surrounded by an
annular aquifer, the method is applicable to arbitrarily-shaped reservoirs. This kind of aquifer model
uses tables of dimensionless time versus a dimensionless pressure influence function.

aquifer 4 aquifer 1

aquifer 3

aquifer 2

Figure 10. Aquifers represented in the model.

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5.2. Fluids properties

A black oil model was designed for the reservoir fluids, the PVT data set used is shown on Figures 11
and 12.

Figure 11. PVT properties for live oil.

Figure 12. PVT properties for dry gas.

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5.3. Rock type properties (SCAL)

Base curves for two phase flow: water/oil and gas/oil systems are derived from the report “Ajwejara
Tertiary Oil Recovery by Lean Gas Injection” (O. Ibrahim and M. Rioche – July 1994). The three
phase permeabilities are calculated in the model using the Stone's 1 model.

These properties are already included in the model in the PROPS section of the AJWEJARA.DATA
file. For example, the curves for the Bar rock type are shown on Figures 17 and 18.

Figure 13. Water/oil saturation functions.

Figure 14. Gas/oil saturation functions.

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VI. The Project

The Reservoir Simulation Project in this class will be dedicated to “Reservoir B“ which is one of the
major accumulations of Ajwejara field, representing 5% of its Total Original Oil In Place.

Oil production starts under natural depletion drive. The original oil in place (OOIP) estimation is about
106.3 MMstb. You must check the OOIP in your printed report, remember that this value is also
dependant on capillary pressure.

Shortly after natural depletion of the reservoir B, which benefit of a strong aquifer, peripheral water
injection must be performed. Water injection eventually becomes the main drive mechanism (Figure
15).

Figure 15. Peripheral water injection.

6.1 Objectives of the Project

The goal of this part is to propose an initial development plan for the Reservoir B of the Main Field
Zone, this plan should maximize the total hydrocarbon production.

Several aspects must be investigated:

1. Using available data, a reservoir performance analysis should identify the main reservoir driving
force. Using material balance, the different drive mechanisms should be investigated in order to
estimate the oil recovery. Primary production as well as secondary production must be
investigated. You must study the solution gas drive mechanism and justify the aquifers size
chosen in the model. Assume a drawdown of 150 psi for PI calculation. For water injection,
consider a drawdown of 120 psi and a skin = 0 in both cases.

2. Based on the characterization of natural reservoir drive mechanisms, evaluate secondary

recovery schemes. Each scenario must be reported in detail with all relevant information,
assumptions and selected options.

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3. Each of the selected scenarios is developed in the numerical reservoir model. Using Reservoir
Simulator, they should be optimized to meet the target production. Determine development well
locations, optimize well spacing, pattern and trajectory and completion strategy issues. The
results of each of the scenarii must be analyzed. Choose one scenario.

6.2. Production constraints

 To develop the Reservoir B in the Main Zone of Ajwejara Field, a platform will be used.
 The production start should be optimized to maintain the reservoir balance.
 Production program should start at the beginning of 2013.
 The average drilling – completion time is about 1 month for vertical wells and 2 months for
horizontal wells.
 Wells may be tied up to production as soon as they are completed.
 The vertical and horizontal wells are drilled in 8½ and equipped with a 7" casing and a 4"½
tubing.
 The maximum drain of a horizontal well will be less than 860 m.
 The minimum tubing head pressure (THP) is 200 psia. Vertical Flow Performance curves are
availables as include files in the AJWEJARA.DATA file for vertical wells only, they are not
available for horizontal wells.
 The perforations of the wells are chosen to optimize recovery depending on the well location.
You must take into account that the drainage radius by well is at least 150 m.
 Vertical well production tests indicate a maximum liquid rate of 2000 stb/d.
 Horizontal well could produce up to 4,500 stb/d of liquid. Only flowing production is
considered at this stage.
 The averaged maintenance down time is 10 % for all the wells.
 Due to surface facilities, the maximum allowable GOR is 2 Mscf/sbl and the maximum
allowable water cut is 90%. The minimum economical rate for any well is 30 stb/d of oil.
 The minimum economical rate for the field is 300 stb/d of oil.
 In case water injection is considered, swamp water may be injected into the reservoir without
any water compatibility problem. Assume properties from PVTW table.
 The fracture pressure of the Ajwejara reservoir is about 4800 psia.

 The maximum water injection rate is 30000 bpd.

 The annual production plateau should be around 8% of the reserves.

 The production profiles should be evaluated over 15 years.

7.3. Reporting

You have to write a comprehensive report of the project that may be outlined below:

o Executive Summary (3 pages)

o Introduction
 Background of Ajwejara Field
 Objectives

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  Scope of the project
o Geological Environment of Ajwejara Field
o Reservoir Characterization Analysis
 Porosity distribution
 Permeability distribution
 Rock types
 PVT analysis data
 Fluid Contacts
o Reservoir Performance Analysis
 Production mechanisms
 Driving force
 Recovery factor by natural depletion and water injection
 Proposal of development plans
o Reservoir Modeling
 Reservoir grid system
 Well trajectory and completion history
 Initialization of the SImulation Model OOIP and OGIP
o Performance Prediction
 Existing conditions
 Infill drilling case
 Water injection scenario with given constraints
o Conclussions and Recommendation
o References

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