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Reservoir Simulation
To run a reservoir simulation model, you must:
(a) Gather and input the fluid and rock (reservoir description)
data; the model incorporates data on the reservoir fluids (PVT)and the reservoir description (porosities, permeabilities etc.) and
their distribution in space.
(b) Choose certain numerical features of the grid (number of grid
blocks, time step sizes etc);
(c) Set up the correct field well controls (injection rates, bottom
hole pressure constraints etc.); it is these which drive the model;
(d) Choose which output (from a vast range of possibilities) you
would like to have printed to file which you can then plot later or -
in some cases - while the simulation is still running.
The output can include the following (non-exhaustive) list of
quantities:
The average field pressure as a function of time
The total field cumulative oil, water and gas production profileswith time
The total field daily (weekly, monthly, annual) production rates
of each phase: oil, water and gas
The individual well pressures (bottom hole or, through lift
curves, wellhead) over time
The individual well cumulative and daily flowrates of oil, water
and gas with time
Either full field or individual well watercuts, GORs, O/W ratios
with time
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The spatial distribution of oil, water and gas saturations
throughout the reservoir as functions of time i.e. So(x,y,z;t),
Sw(x,y,z;t) and Sg(x,y,z;t)
The central objective of reservoir simulation is to produce futurepredictions (the output quantities listed above) that will allow us
to optimise reservoir performance. At the grander scale, what is
meant by optimise reservoir performance is to develop the
reservoir in the manner that brings the maximum economic
benefit to the company
Appraisal stage: at this stage, reservoir simulation will be a tool
that can be used to design the overall field development plan in
terms of the following issues:
The nature of the reservoir recovery plan e.g. natural depletion,
waterflooding, gas injection etc.
The nature of the facility required to develop the field e.g. a
platform, a subsea development tied back to an existing platform
or a Floating Production System (for an offshore fileld).
The nature and capacities of plant sub-facilities such as
compressors for injection, oil/water/gas separation capability.
The number, locations and types of well (vertical, slanted or
horizontal) to be drilled in the field.
The sequencing of the well drilling program and the topside
facilites.
It is during the initial appraisal stage that many of the biggest -
i.e. most expensive- investment decisions are made e.g. the type
of platform and facilities etc. Therefore, it is the most helpful time
to have accurate forward predictions of the reservoir
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performance. But, it is at this time when we have the least
amount of data and, of course, very little or no field performance
history (there may be some extended production well tests).
In such cases, we may still be able to build a range of possiblereservoir models, or reservoir scenarios, that incorporate the
major uncertainties in terms of reservoir size (STOIIP), main fault
blocks, strength of aquifer, reservoir connectivity, etc. By running
forward predictions on this range of cases, we can generate a
spread of predicted future field performance cases
For example, scenarios for various cases may involve:
Different assumptions about the original oil in place (STOIIP;
Stock Tank Oil Originally In Place).
Different values of the reservoir parameters such as
permeability, porosity, net-to-gross ratio, the effect of an aquifer,
etc..
Major changes in the structural geology or sedimentology of the
reservoir e.g. sealing vs. leaky faults in the system, the
presence/absence of major fluvial channels, the distribution of
shales in the reservoir etc..
Mature field development: has been in production for some
time
(2 - 20+ years) but there is still a reasonably long lifespan ahead
for the field, say; 3 - 10+years. At this stage, reservoir simulation
is a tool for reservoir management which allows the reservoirengineer to plan and evaluate future development options for the
reservoir. This is a process that can be done on a continually
updated basis. The main difference between this stage and
appraisal is that the engineer now has some field production
history, such as pressures, cumulative oil, watercuts and GORs
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(both field-wide and for individual wells), in addition to having
some idea of which wells are in communication and possibly some
production logs. The initial reservoir simulation model for the field
has probably been found to be wrong, in that it fails in some
aspects of its predictions of reservoir performance e.g. it failed topredict water breakthough in our waterflood (usually, although
not always, injected water arrives at oil producers before it is
expected).
At this development stage, typical reservoir simulation activities
are as follows:
Carrying out a history match of the (now available) field
production history in order to obtain a better tuned reservoirmodel to use for future field performance prediction
Using the history match to re-visit the field development
strategy in terms of changing the development plan e.g. infill
drilling, adding extra injection water capability, changing to gas
injection or some other IOR scheme etc.
Deciding between smaller project options such as drilling an
attic horizontal well vs. working over 2 or 3 existingvertical/slanted wells
It may be necessary to review the equity stake of various
partner companies in the field after some period of production
although this typically involves a complete review of the
engineering, geological and petrophysical data prior to a new
simulation study
The reservoir recovery mechanisms can be reviewed using acarefully history matched simulation model e.g. if we find that, to
match the history, we must reduce the vertical flows (by lowering
the vertical transmissibility), we may wish to determine the
importance of gravity in the reservoir recovery mechanism:
educational value of simulation models and it is a part of good
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reservoir management that the engineer has a good grasp of the
important reservoir physics of their asset.
Late field development: we define this stage of fielddevelopment as the closing few years of field production before
abandonment. A question arises here as to whether the field is of
sufficient economic importance to merit a simulation study at this
stage. However, there are two reasons why we may want to
launch a simulation study late in a fields lifetime. Firstly, we may
think that, although it is in far decline, we can develop a new
development strategy that will give the field a new lease of life
and keep it going economically for a few more years. Forexample, we may apply a novel cheap drilling technology, or a
program of successful well stimulation (to remove production
impairment such as mineral scale) or we may wish to try an
economic Improved Oil Recovery (IOR) technique. Secondly, the
cost of field abandonment may be so high - e.g. we may have to
remove an offshore structure - that almost anything we do to
extend field life and avoid this expense will be economic. This
may justify a late life simulation study. However, there are nogeneral rules here since it depends on the local technical and
economic factors which course of action a company will follow. In
some countries there may be legislation (or regulations) that
require that an oil company produces reservoir simulation
calculations as part of their ongoing reservoir management.
(A 5-spot is a particular example of a pattern flood
which is appropriate mainly for onshore reservoirs where
many wells can be drilled with relatively close spacing)
The structure of the simulation study work flow: Accurate
reservoir description
- Develop the simulation model (perform the history
match - see below - use model for future predictions -
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evaluate alternative operating plans). A history match is
when we adjust the parameters in the simulation model to
make the simulated production history agree with the
actual field performance
Pressure transient work - again gives important ancillary
information on the reservoir; determine whether there
was (i) directional permeability effects, directional
fracturing or channelling; (ii) the degree of stratification
in the reservoir; (iii) evaluation of the pay continuity
between the injectors and producers
A list of possible sources of uncertainty is as follows:
Lack of knowledge or wide inaccuracies in the size of the
reservoir; its areal extent, thickness and net-to-gross ratios
Lack of knowledge about the reservoir architecture i.e. its
geological structure in terms of sandbodies, shales, faults, etc.
Uncertainties in the actual numerical values of the porosities ()
and permeabilities (k) in the inter-well regions (which make upthe vast majority of the reservoir volume)
Inaccuracy in the fluid properties such as viscosity of the oil
(o), formation volume factors (Bo, Bw, Bg), phase behaviour etc.,
or doubts about the representativity of these properties
Lack of data - or very uncertain data- on the multiphase
fluid/rock properties, particularly relative permeability and
capillary pressure, and on knowledge as to how these curves varyfrom rock type within the reservoir volume away from the wells
Because the representational reservoir simulations model may
be poor, e.g. the numerical errors due to the coarse grid block
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model may significantly affect the answer in either an optimistic
or pessimistic manner.
The above list of uncertainties for a given reservoir, especially at
the appraisal stage, is really quite realistic
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