Introduction
The main source of energy during primary hydrocarbon recovery is the pressure of
the reservoir. At any given time in the reservoir, the average reservoir pressure is an
indication of how much gas, oil or water is remaining in the porous rock media. This
represents the amount of the driving force available to push the remaining hydrocarbon out of the reservoir during a production sequence. Most reservoir systems are
identified to be heterogeneous and it is worthy to note that the magnitude and
variation of pressure across the reservoir is a paramount aspect in understanding
the reservoir both in exploration and development (production) phases (Fig. 8.1).
Hydrocarbon reservoirs are discovered at some depths beneath the earth crust as a
result of depositional process and thus, the pore pressure of a fluid is developed
within a rock pore space due to physical, chemical and geologic processes through
time over an area of sediments. There are three identified pressure regimes:
• Normal (relative to sea level and water table level, i.e. hydrostatic)
• Abnormal or overpressure (i.e. higher than hydrostatic)
• Subnormal or underpressure (i.e. lower than hydrostatic)
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Fluid pressure regimes in hydrocarbon columns are dictated by the prevailing
water pressure in the vicinity of the reservoir (Bradley 1987). In a perfectly normal
pressure zone, the water pressure at any depth can be calculated as:
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Pressure Regime of Different Fluids
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Some Causes of Abnormal Pressure
• Incomplete compaction of sediments
Fluids in sediments have not escaped and are still helping to support the overburden.
• Aquifers in Mountainous Regions
Aquifer recharge is at higher elevation than drilling rig location.
• Charged shallow reservoirs due to nearby underground blowout.
• Large structures
• Tectonic movements
Abnormally high pore pressures may result from local and regional tectonics. The
movement of the earth’s crustal plates, faulting, folding, lateral sliding and slipping,
squeezing caused by down dropped of fault blocks, diapiric salt and/or shale
movements, earthquakes, etc. can affect formation pore pressures.
Due to the movement of sedimentary rocks after lithification, changes can occur
in the skeletal rock structure and interstitial fluids. A fault may vertically displace a
fluid bearing layer and either create new conduits for migration of fluids giving rise
to pressure changes or create up-dip barriers giving rise to isolation of fluids and
preservation of the original pressure at the time of tectonic movement.
When crossing faults, it is possible to go from normal pressure to abnormally high
pressure in a short interval. Also, thick, impermeable layers of shale (or salt) restrict
the movement of water. Below such layers abnormal pressure may be found. High
pressure occurs at the upper end of the reservoir and the hydrostatic pressure gradient
is lower in gas or oil than in water.
8.4 Fluid Contacts
In the volumetric estimation of a field’s reserve, the initial location of the fluid
contacts and also for the field development, the current fluid contacts are very critical
factor for adequate evaluation of the hydrocarbon prospect. Typically, the position of
fluid contacts are first determined within control wells and then extrapolated to other
parts of the field. Once initial fluid contact elevations in control wells are determined,
the contacts in other parts of the reservoir can be estimated. Initial fluid contacts
within most reservoirs having a high degree of continuity are almost horizontal, so
the reservoir fluid contact elevations are those of the control wells.
Estimation of the depths of the fluid contacts, gas/water contact (GWC), oil/water
contact (OWC), and gas/oil contact (GOC) can be made by equating the pressures of
the fluids at the said contact. Such that at GOC, the pressure of the gas is equal to the
pressure of the oil and the same concept holds for OWC.
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Methods of Determining Initial Fluid Contacts
8.4.1.1 Fluid Sampling Methods
This is a direct measurement of fluid contact such as: Production tests, drill stem
tests, repeat formation tester (RFT) tests (Schlumberger, 1989). These methods have
some limitation which are:
• Rarely closely spaced, so contacts must be interpolated
• Problems with filtrate recovery on DST and RFT
• Coring, degassing, etc. may lead to anomalous recoveries
8.4.1.2 Saturation Estimation from Wireline Logs
It is the estimation of fluid contacts from the changes in fluid saturations or mobility
with depth, it is low cost and accurate in simple lithologies and rapid high resolution
but have limitations as:
• Unreliable in complex lithologies or low resistivity sands
• Saturation must be calibrated to production
8.4.1.3 Estimation from Conventional and Sidewall Cores
Estimates fluid contacts from the changes in fluid saturation with depth which can be
related to petrophysical properties. It can estimates saturation for complex lithologies (Core Laboratories, 2002). The limitations are:
• Usually not continuously cored, so saturation profile is not as complete
• Saturation measurements may not be accuratPressure Methods
There are basically two types of pressure methods: the pressure profiles from repeat
formation tester and pressure profiles from reservoir tests, production tests and drill
stem tests.
8.4.1.5 Pressure Profiles from Repeat Formation Tester
It estimates free water surface from inflections in pressure versus depth curve.
8.4.1.6 Pressure Profiles from Reservoir Tests, Production Tests
and Drill Stem Tests
It estimates free water surface from pressures and fluid density measurements which
makes use of widely available pressure data.
Both pressure techniques are pose with limitations such as:
• Data usually require correction
• Only useful for thick hydrocarbon columns
• Most reliable for gas contacts, Requires many pressure measurements for profile,
Requires accurate pressurese
Estimate the Average Pressure from Several Wells
in a Reservoir
When dealing with oil, the average reservoir pressure is only calculated with material
balance when the reservoir is undersaturated (i.e when the reservoir pressure is
above the bubble point pressure). Average reservoir pressure can be estimated in
two different ways but are not covered in this book (see well test analysis textbooks
for details).
• By measuring the long-term buildup pressure in a bounded reservoir. The buildup
pressure eventually builds up to the average reservoir pressure over a long enough
period of time. Note that this time depends on the reservoir size and permeability
(k) (i.e. hydraulic diffusivity).
• Calculating it from the material balance equation (MBE) is given below
For a gas well
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