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Tui Amokura Pateke Oil Reserves


Tui Amokura Pateke Oil Reserves

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									Tui - Amokura - Pateke:               Oil Reserves Modeling

Reserve calculation factors                    Low              Mid          High
                                               case             case         case

Net pay to gross pay %                          100              100          100

Porousity %                                     18               22           26

oil Saturation %                                75               80           85

Recovery factor %                               45               50           55

Shrinkage factor %                              85               90           95
(100 x 1/formation volume factor)

NPSRS (factors multiplied as fractions)        0.052            0.079        0.115

Net Reservoir Volume (m3)                    68,179,700       77,887,100   83,434,300
(from contour modeling)

Net Reservoir Volume x NPSRS (m3)            3,520,629        6,168,658    9,634,367

Reserves -- barrels oil (bo)                 22,143,350       38,798,393   60,596,316
(m3 to bo = 6.2896, Santos website)

Reserves (mmbo)                                22.1             38.8         60.6
(producible barrels at the surface)
Oil Reserves formula:


(see model answers, last question – with some minor modifications)

Reserves = net reservoir volume x porosity x oil saturation x recovery factor x shrinkage

Net reservoir volume: Area under closure, defined as volume between the seal and the oil-
water contact, which is of reservoir quality (i.e. conforms to the porosity and permeability criteria
for a reservoir at that location).

Porosity: Proportion of the net reservoir with effective porosity – i.e. connected pore space.
Porosity determined using core or wireline techniques to measure or estimate. Wireline tools
include density, sonic, neutron and resistivity.

Saturation: Proportion of the pore space which is occupied by oil. Determined from wireline
data, particularly resistivity tools, using Archie Formula.

Recovery factor: Proportion of the in-situ oil-in-place which can be recovered at the surface
using known technology. Recovery factors are generally in the range 30 – 60 % for oil fields, and
have improved over the last 40 years due to secondary and tertiary recovery techniques, such
as water flooding, gas injection, hydraulic fracture stimulation. Information comes from
engineering data and production experience of nearby fields.

Shrinkage factor: Proportion of remaining oil volume at the surface after internal gas has
exsolved ( = 1/(formation volume factor)). Related to the gas-oil ratio (GOR). As oil moves
towards the surface and lower pressures, gas comes out of solution and must be separated. The
volume of oil reduces in proportion to the gas coming out of solution. Information comes from
analysis of the oil and PVT property determination in a laboratory.

15000.00                             Pateke-2


13000.00                                  Ip4




 9000.00                                                              Tui-1


           3000.00          5000.00               7000.00   9000.00    11000.00
TAP Contouring – top F sand depth to OWC

                  Coordinates (m)     Top F sand depth to OWC (m)

                     X           Y   Low Case   Mid Case   High Case

     Tui-1         10630     9279       10        10          10
      Ip1          10528     8446        7         8           9
      Ip2          10871     9859        6         7           8

  Amokura-1        7067     11350       12        12          12
     Ip2           6683     11970        8        10          11
     Ip3           6154     12450        6         8           9
     Ip4           5817     13220        6         8           9
     Ip5           5673     13890        8        10          11
     Ip6           5625     14520       10        11          12

   Pateke-2        5817     15100       13        13          13
      Ip7          6250     15430       10        11          12
      Ip8          6635     15770        6         8           9
      Ip9          5625     15620        8        11          12
     Ip10          5237     16066        6         9          10
     Ip11          4693     16741        9        11          12
     Ip12          3968     16904        8        10          11

OWC = oil water contact

Ip = interpolated point

Coordinates use a local origin
TAP contouring: Mid Case – top F sand depth to OWC












           3000.00   5000.00   7000.00   9000.00   11000.00

Blue contour = oil water contact (OWC)
TAP 3D contouring: Mid Case – top F sand depth to OWC


3D view has approx 1:100 vertical exaggeration

Gross Reservoir Volume = (positive surface) – (OWC horizontal plane)

(OWC = 0 m contour)

Ned Etris and Bruce Stewart
Core Lab Reservoir Technologies Division, Calgary, Canada

“Net-to-gross   ratio” is one of those terms that can mean
different things to different disciplines, often causing confusion
and misunderstanding.

So what could “net-to-gross” mean? The quick answer to
some is: it doesn‟t matter; it is net pay that matters! The more
helpful answer is: “It depends.” Which net and which gross
is the speaker is talking about? Is it gross thickness, gross
reservoir, or gross pay?

To sort out the confusion, there are several terms (and
combinations of terms) to understand: net, gross, thickness,
pay, and reservoir. Basically, „pay‟ means rock within the
hydrocarbon zone, „reservoir‟ means rock capable of flowing
any fluid, including water, and „net‟ means rock that exceeds
various cutoffs defined by an analyst. Put the terms together
in various ways and you can get:

1) Gross thickness. This is customarily used to refer to a
lithologic or sequence stratigraphic unit and doesn‟t have
anything to do with fluids. It simply represents all rock
between the top pick and bottom pick for a unit.

2) Net thickness. This is the total interval of reservoir
quality rock within the gross thickness – that is, rock that will
flow fluids. To be part of the net thickness, a rock‟s properties
must exceed some defined thresholds, called cutoffs. The
criteria for the establishment of cutoffs can be a complex
subject by itself.

3) Gross reservoir. This means the thickness of the unit
from the highest part to the lowest part that is reservoir
quality, but this obviously can include tight rock (immobile
fluids) inter-bedded with reservoir quality rock. Hence gross
reservoir can be a subset of gross thickness. Geologists often
map this instead of gross thickness, in which case it substitutes
for gross thickness.

4) Net reservoir. This is the total thickness of reservoir
quality rock within the gross reservoir, and is therefore identical
to the net thickness defined above. It is the sum of the
thicknesses of the individual reservoir quality beds within
the gross unit. (Imagine distilling off the non-reservoir rock
and leaving behind only the good stuff.) Although this is a
more descriptive term than net thickness, it is not as widely

5) Gross pay. This is the thickness of rock from the highest
point of hydrocarbon saturation (usually the base of the top
seal of the reservoir) to the lowest point, which is not necessarily
the base of the reservoir (if a hydrocarbon-water
contact is present). Like gross reservoir, though, this interval
may include non-reservoir and, therefore, non-net pay rock,
but it is often smaller than gross reservoir because of the
presence of water. (We ignore capillary pressure and transition
zone effects in this article because they are a complication
unnecessary for the general understanding of the terms
of interest.)

6) Net pay. This is the total thickness of reservoir quality
rock that will flow some amount of hydrocarbons from rock
exceeding user-determined cutoffs. It is the sum of the thicknesses
of the individual reservoir quality beds within the
gross pay unit. (Again, imagine distilling off the non-reservoir
rock and leaving behind only the good stuff, but in this
case not including rock containing substantial amounts of

So, what does a person mean when he says, “net-to-gross
ratio?” Guess what? You can‟t tell without checking the gist
of the conversation, or the mapping if it is provided, because
the ratio could refer to thickness or to pay! One supposes to
be more informative we should say “net-to-gross thickness”
and “net-to-gross pay,” but these terms are not widely used.

In our experience, the most common usage of net-to-gross
ratio among flow simulation engineers refers to net-thickness-
to-gross-thickness, because its main use in reservoir flow
simulators is to determine the volume of rock holding a
mobile fluid, whether gas, oil, or water. (Flow simulators
don‟t even know about the non-flowing rock that may be part
of gross thickness; they ignore it. But flow simulators care
about flowing water as much as about flowing hydrocarbons,
because it provides critically important pressure support.)
The actual volume of hydrocarbon is then determined by
taking into account the hydrocarbon-water contact.

By contrast, within the context of reserves calculations,
net-to-gross ratio is usually the ratio of net pay to gross pay,
because its main purpose is to determine the volume of
hydrocarbons in place.

saturation         (1) The fraction or percentage of the pore volume occupied by a
                   specific fluid (e.g., oil, gas, water, etc.). The fluids in the pore spaces
                   may be wetting or nonwetting. In most reservoirs, water is the wetting
                   phase, but a few reservoirs are known to be oil wet. The wetting phase
                   exists as an adhesive film on the solid surfaces. At irreducible
                   saturation of the wetting phase, the nonwetting phase is usually
                   continuous and is producible under a pressure gradient to the well bore.

                   (2) The occupation of fluids in a pore may take different forms:

                      a. Funicular saturation. A form of saturation in which the
                         nonwetting phase exists as a continuous web throughout the
                         interstices. The nonwetting phase is mobile under the influence
                         of a hydrodynamic pressure gradient. The wetting phase might
                         or might not be at irreducible saturation. In the illustration, the
                         oil in the "A" figure is funicular
                      b. Pendular saturation. The wetting phase exists in a pendular form
                         of saturation. An adhesive fluid film of the wetting phase coats
                         solid surfaces, grain-to-grain contacts, and bridges fine
                         interstices or pore throats. The wetting phase might or might not
                         be at irreducible saturation. In the illustration, water in the "A"
                         and "B" figures is pendular.
                      c. Insular saturation. A form of saturation in which the nonwetting
                         phase exists as isolated insular globules within the continuous
                         wetting phase. A drop in pressure might or might not cause the
                         insular globules to collect into a continuous phase. In the
                         illustration oil in the "B" and "C" figures is insular.

Recovery factors for existing oil fields – Norwegian North Sea

Of the 39 oil fields that are in production or for which an approval for development is given
(resource classes 1-2), as of 31.12.96, 33 have reservoirs in sandstone. Reserves in these fields
(including additional resources in Troll II), are estimated to be 2540 million Sm3 of oil. This
corresponds to an average recovery factor of approximately 45%.

In addition, oil reserves in 6 fields with chalk reservoirs, estimated to be 640 million Sm3 oil,
have an average recovery factor of 32%. Taken together, these give an expected average
recovery factor of just under 42% for all the fields in resource classes 1 and 2. If resources from
the potential for improved resource exploitation, placed in classes 3-6, are also included, the
average recovery factor is increased to 45%. The in place resources in the 39 fields make up 80%
of the total discovered in place oil resources.

Several major oil fields with sandstone reservoirs currently have a relatively high recovery
factor, also in an international context. For instance the Gullfaks, Oseberg and Statfjord fields,
together, have oil reserves which give an average recovery factor of just under 60%.

If gas injection is used, it is expected that a few reservoirs will achieve a significantly higher
recovery factor. The recovery factor for parts of the Statfjord field is expected to be as high as
74%. On the other hand, two of the large chalk fields, the Eldfisk and Valhall fields, have oil
reserves whose average recovery factor is only 24%. The challenges here will consist of
understanding the reservoir behaviour and of implementing measures, such as gas or water
injection, to increase the recovery.

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