INTRODUCTION TO FORMATION EVALUATION.
Petroleum companies drill exploration wells to find new
accumulations of hydrocarbons. Most of the oil and gas, that is produced nowadays,
comes from hydrocarbon accumulations in the pore spaces of reservoir rocks –
usually sandstones, limestones or dolomites.
In order to calculate the amount of oil or gas that a unit
volume of the reservoir contains, we multiply the porosity of the rock
with the hydrocarbon saturation of the rock.
To get an idea of the reserve found in a formation we have
to multiply this product again with the volume of the formation containing the
hydrocarbons. To calculate this volume, we need to know the thickness
and the lateral extent of the hydrocarbon-bearing portion of the
formation, i.e. the size of the reservoir.
For the evaluation of the producibility of the reservoir we
need to know how easily the hydrocarbons will flow through the pore spaces in
the reservoir, i.e. the permeability of the reservoirs.
So, in order to get an idea of the commerciality of the new
accumulation or reservoir, we need to know some basic petrophysical parameters:
porosity, hydrocarbon saturation, height
of column, areal extent and permeability.
To appreciate the role of Formation Evaluation in the
operations of petroleum companies, let us look at the formula for the
calculation of the original oil in place for a reservoir.
STOOIP = (7758*A*h*p*(1-Sw))/Boi
Where:
STOOIP is stock tank volume of the original oil in place, in
barrels
A is the reservoir closure area, in acres
h is the average reservoir (net) thickness, in feet
p is the average reservoir porosity, fractional
Sw is the average reservoir water saturation, fractional.
Boi is the initial oil formation volume factor, and
7758 is the acre-ft to Bbls conversion factor.
A similar relationship also exists for gas reserves. Three
of the five variables (h, p and Sw) are obtained from well logs, via Formation
Evaluation. The emphasis in this blog will be on how to obtain values for these
variables.
Porosity
Porosity is the pore volume per unit volume of rock; it is
the percentage of the total volume of the rock that is occupied by the pores.
Porosity can vary widely, from large pores in karstified limestones to very low
porosity in anhydrite and quartzites. Well consolidated or deeply buried,
sandstones may have porosities from 10 -15%. The more consolidated sandstones
of the Niger Delta usually have porosities in the range of 22 – 28%, while the
unconsolidated sands of the Niger Delta may have porosities of 30% or higher.
Shales and clays have a large pore volume (40%) that is occupied with water.
However, the mobility of the water in the very small pore spaces is so low,
that the rock is impervious to the flow of fluids.
In reservoir rocks we can identify two types of porosity: primary porosity, which is the original
pore space of the rock from when it was deposited, and secondary porosity, such as vugs, which is caused by
post-depositional processes, such as tectonic forces or by formation water
flows. Secondary porosity is most likely to occur in carbonates, when slightly
acidic waters are percolating through the rock. On the other hand, when water,
rich in minerals, moves through the rock or reservoir, it may form deposits on
the matrix of the rocks (cementation), thus decreasing the original pore
volume.
Stresses on the rock may cause it to break, which may result
in a network of fractures throughout the rocks. These fractures do not add
significantly to the overall porosity of the rock, but their permeability is
relatively high because they form “straight channels”.
Saturation
Saturation of a reservoir is that portion of its pore volume
that is occupied by the fluid considered. In formation evaluation, water
saturation is commonly considered the standard, thus it that percentage of the
pore volume that contains the formation water. If it is the only fluid present
in the rock, the water saturation will be 100%. The hydrocarbon saturation (So
or Sg) is that portion of the pore volume not occupied by the formation water
or water saturation (Sw) and can be calculated as 100 – Sw.
Water saturation in reservoirs can vary from 100% to very
low values, but will never be zero (0%). Under normal conditions no pressure
will be high enough to displace all the water in the pore space. This residual
water is called irreducible water or
connate water.
The same is true in drained hydrocarbon reservoirs; there
will always be some hydrocarbon that remained behind in the pore spaces; this
is called the residual oil or gas
saturation of the rock.
A reservoir that has a Sw = 100% near the base and is filled
with oil at the top, has a zone where a gradual change takes place from 100% Sw
to a water saturation at which no water will be produced. This zone is called
the transition zone and its thickness depends mainly on permeability of the
rock. Above the transition zone capillary forces retain some water around the
grains of the rock and this water cannot be displaced. The water above the
transition zone is at irreducible levels, so no water production can be
expected there. In the transition zone we can expect production of water and
hydrocarbon at the same time. We can expect a long or thick transition zone in
low-permeability rocks, while reservoirs with good permeabilities, in general,
will have a short transition zone.
Permeability
Permeability is a measure of the ease with which fluids can
flow through rock. Permeability is generally expressed in units of darcy, but
since most rocks don’t have permeabilities so high as to be in the darcy range,
the millidarcy (md) unit is more practical to use (1 md = 1/1000 darcy).
Permeability is somewhat related to porosity, because flow
of fluids in the rock will use the pores, fractures, etc, as the passage way.
Generally, higher permeabilities are associated with higher porosities,
especially in clastic reservoirs, but this is no absolute rule. Shales, which
usually have high porosities, generally have very low permeabilities. The grain
sizes are so small, making the flow path very tortuous, and also the pore
openings are very small, restricting flow.
Fractured, dense rocks, such as limestones, may have very
low porosities, but the fractures provide a good path for fluid flow, resulting
in very high permeabilities.
The formation evaluation analyst derives all his parameters
from several different sources. This main
source of information lies in the wireline logs run in the borehole, but mud logging operations provide
additional useful information; cores
and formation test data, when
available, can help him in his effort to establish reliability of his initial
wireline log interpretation.
The wireline logs can
help him in calculating or at least give him a good idea of:
- Porosity
- Permeability
- Water saturation and hydrocarbon movability
- Type of hydrocarbons
- Lithology
- Formation dip and strike
Using the above items, a good estimate can be made of the
type reservoir, its size and the total of hydrocarbons in place.
The sequence in which a well gets analyzed follows a certain
pattern. The first information of the subsurface is obtained from mud logging
or measurements made while drilling
(MWD, LWD). When zones of interest are encountered, decisions are made
whether to cut cores for detail analysis
on porosity and permeability. Once total depth has been reached, wireline
logs are run. Initial interpretation
of the wireline and mud log data leads to decisions on whether to take more
samples from the zones of interest (sidewall
samples) and/or to test the
zones (RFT, DST). If the zones prove
to be productive and the well or field economically interesting, more extensive
core analysis work may be requested.
The initial uses of wirelines measurements were to correlate
between boreholes. This is still the largest single use of wireline products.
Quantitative wireline measurement tools and laboratory
measurements on core material led to the development of Formation Evaluation,
or Petrophysics, initially wireline measurements were calibrated, using core measurements as standards. Current wireline
tools, however, are sufficiently reliable and well calibrated, that they can
often identify core measurements which are in error, or are biased by
inhomogeneities.
Wireline measurement suites are now routinely used to scan
drilled intervals to search for potential hydrocarbon-bearing intervals. Once
hydrocarbon indication have been found, wireline measurements are used to
quantify the reservoir pore spaces (porosity), and the type and amounts of
fluids occupying that pore spaces (water, oil and gas saturation). This basic
reservoir information (porosity and saturation) is used with structural and
stratigraphic information to develop STOOIP values for reserves estimates and
depletion management.
ORDER OF INFORMATION
REACHING THE ANALYST.
· MUDLOG
· MWD AND LWD
· CORES
· WIRELINE LOGS
· SIDEWALL SAMPLES
· RFT’S AND DST’S
