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A B S T R A C T S F R O M P U B L I S H E D P A P E R S
The following are abstracts drawn from selected papers authored or co-authored by our Principal Petrophysicist .
SPE 93125 - Quantifying Petrophysical Uncertainties
by S.J. Adams, WellEval.com
Prepared for the SPE sia-Pacific Oil & Gas Exhibition in Jakarta, 5-7 April 2005.
Typical petrophysical deliverables for volumetric and modeling purposes
are net reservoir, porosity, permeability, water saturation and contact
locations. These data are usually provided without quantitative
determination of their uncertainties. Current computing power renders
it now feasible to use Monte-Carlo simulation to determine the
uncertainty in petrophysical deliverables. Unfortunately, quantitative
uncertainty definition is more than just using Monte-Carlo simulation
to vary the inputs in your interpretation model. The largest source of
uncertainty may be the interpretation model itself.
This paper will use a variety of porosity interpretation models to
illustrate how the impact of each input on the uncertainty varies with
the combination of input values used in any given model. It will show
that use of the incorrect model through oil and gas zones may give
porosity estimates with Monte-Carlo derived uncertainty ranges that
exclude the actual porosity.
Core data provides the best means of quantifying actual uncertainty in
the petrophysical deliverables. Methodologies for deriving
uncertainties quantitatively by comparison with core data will be
presented. In the absence of core data, interpretation models should
have been tested against core data through the same or similar
formations nearby. Monte-Carlo simulation can then be used as an
effective means of quantifying petrophysical uncertainty. Comparisons
between the core comparison and Monte-Carlo techniques will be made,
showing that similar results are achieved with the appropriate
interpretation models.
The methodologies described in this paper are straightforward to
implement and enable petrophysical deliverables to be treated
appropriately in volumetric and modeling studies. In addition,
quantification of petrophysical uncertainty assists in operational
decision-making by letting users know how reliable the numbers produced
actually are, and what range of properties is physically realistic.
Such work also allows the key contributions to uncertainty to be
defined and targeted if overall volumetric uncertainty must be reduced.
SPE 84298 - Modelling Imbibition Capillary Pressure Curves
by S.J. Adams, WellEval.com
Presented at the SPE Annual Technical Conference & Exhibition in Denver, 6-8 October 2003.
Although imbibition capillary pressures are relevant in all reservoirs
having undergone or undergoing water displacement, imbibition capillary
pressure curves are not commonly measured nor considered for reservoir
modelling. Imbibition is particularly important when establishing
initial hydrocarbons in place for reservoirs with residual hydrocarbon
columns.
As part of a saturation-height study undertaken, laboratory
measurements of both drainage and imbibition capillary pressure curves
were used to create an empirical model relating imbibition capillary
pressure curves to their drainage precursors. Drainage
saturation-height functions could then be used to create imbibition
equivalents based upon the saturation history of the reservoir rock.
The model was verified against log derived water saturations from wells
in the initial Fields being studied, even proving able to describe
imbibition capillary pressure curves for sections of reservoir in
drainage transition zones prior to the commencement of water
imbibition. Since then, the model has also been verified in three other
hydrocarbon accumulations found in different basins.
The “imbibition from drainage” (IFD) model developed
represents the first publication of a technique for creating meaningful
imbibition capillary pressure curves and imbibition saturation-height
functions for reservoirs with significant capillary transition zones.
The IFD technique should be widely used to describe water saturations
in reservoirs with residual hydrocarbon columns, providing better
estimates of initial hydrocarbons in place than with more commonly used
drainage data. Iteration of the model also allows determination of both
original and current day Free Water Level locations in systems having
residual hydrocarbon columns from either leakage prior to production or
from water sweep during production.
SPE 77886 - New Insight into Eromanga Basin Oil Saturations
by S.J. Adams, WellEval.com Limited
Presented at the SPE Asia-Pacific Oil & Gas Exhibition in Melbourne, 8-10 October 2002.
The Eromanga Basin is an established Australian producing region with
oil and gas found in several different Formations. At the request of an
Operator, a project was undertaken to construct saturation-height
functions for all the Eromanga reservoir units with a secondary
objective being to define residual hydrocarbon saturations.
Initial investigations revealed many reservoirs with residual
hydrocarbon columns, the significance of which had not been well
understood. The residual hydrocarbons implied that imbibition, rather
than drainage, capillary pressure curves were representative of water
saturations in the reservoir. This insight suggested higher
oil-in-place and reserves volumes than previously assumed since mobile
hydrocarbons were present much closer to the pressure derived
Free-Water Levels.
When individual hydrocarbon Fields were considered, there were
insufficient special core analyses to derive meaningful residual
hydrocarbon or saturation-height relationships. However, on the basin
scale, a significant volume of measurements had been acquired over a
period of 22 years using different laboratories and a variety of
measurement techniques. With knowledge of the measurement techniques
and Formations sampled, it proved possible to combine the data in such
a way that consistent datasets were obtained for end-point relative
permeabilities and drainage and imbibition capillary pressure curves.
Interpretation of these datasets produced residual oil saturation and
drainage and imbibition saturation height relationships. These
relations were tested against those log-derived water saturations
considered most reliable, showing excellent matches. The model
developed successfully described the water saturation distributions in
the reservoirs tested in a manner not previously possible. Indeed, the
use of the drainage and imbibition saturation-height functions together
with residual hydrocarbon relationships provides a powerful tool to
determine both static and dynamic fluid contacts, while checking the
validity of wireline log-based water saturations.
SPE 64408 - Fracture Porosity from Conventional Logs with Image Tool Calibration
by S.J. Adams, Petrophysical Solutionz Limited
Presented at the SPE Asia-Pacific Oil & Gas Exhibition in Brisbane, 16-18 October 2000.
Petrophysical evaluation of the Moki Formation in the Toka-1
exploration well, required rapid quantification of fracture porosities,
enabling likely hydrocarbon volumes to be estimated.
A resistivity imaging tool had been run over the approximately 400m of
fractured interval. This information was being processed for fracture
apertures by the acquisition contractor, but the rate of quantification
was too slow to meet the operators objectives.
A technique was developed to rapidly estimate fracture porosities using
the difference between the density and the compressional sonic
porosities and the difference between the shear and compressional sonic
porosities. The fracture porosity estimates were cross-checked against
the image log analysis completed. Owing to washouts across the most
heavily fractured intervals, it was expected that fracture porosities
from the density and compressional sonic logs were maximum values. The
most likely fracture porosities were thought to be those derived using
the shear and compressional velocities. The fracture porosities
estimated by hand-picking fractures from the image data were considered
the minimum values, since the identification process was incomplete.
The work described represents a new technique for fracture porosity
quantification. The comparison with image log interpretation over a
short interval gives confidence in the methodology. The results are
significant in that they show rapid quantification of fracture porosity
is possible by using conventionally acquired logs, although it should
be recognised that the uncertainty in this approach is significant.
Application of this technique to other fields with limited image data
may prove helpful in reservoir modelling and understanding of
production behaviour.
Laboratory and In-Situ Determination of Residual Gas Saturations in Maui
by S.J. Adams, R.G. Farmer, D. Hawton & O. Seybold
Presented at the New Zealand Petroleum Conference, Christchurch, 19-23 March 2000.
A review has been undertaken of the residual gas saturations in the
main producing sands of the Maui Gas Field. Additional laboratory data
has been acquired and interpreted to address recognised deficiencies in
the existing dataset.
Residual gas saturation in the Maui Field has been shown to be
dependent on the initial gas saturation in the individual rock sample.
Relationships representing the high, expectation and low case residual
gas saturations have been derived from the laboratory results and
checked against field measurements using pulsed neutron logs.
The work described herein supports a decrease in the most likely value
of the residual gas saturations and, as a direct consequence, the
remaining reserves of the Maui Field have increased significantly.
Modelling Maui with Imbibition Capillary Pressure Curves
by S.J. Adams, RG Farmer & E van den Heuvel
Presented at the New Zealand Petroleum Conference, Queenstown, 30 March-1 April 1998.
Transition zones evaluated from logs in the large Maui
gas/condensate/oil field, offshore Taranaki, New Zealand (operator
Shell Todd Oil Services Ltd), are significantly shorter than can be
explained using conventional capillary pressure considerations.
This paper describes the investigation carried out to determine whether
water imbibition prior to Field discovery could explain the
discrepancy. Work involved a field-wide petrophysical review together
with the acquisition of a representative set of imbibition capillary
pressure curves. These data were combined to yield an excellent match
with the log-based gas saturations, showing that imbibition is an
appropriate explanation for the short transition zones observed.
As a consequence of these short transition zones, an increase in the
estimated C sand gas-initially-in-place (GIIP) for Maui has been
justified. The concept of imbibition is also impacting on understanding
of the deeper D and F sand reservoirs in the Maui Field.
SPE 21414 - Gas Saturation Monitoring In North Oman Reservoirs Using A Borehole Gravimeter
by S.J. Adams
Following partial implementation of gas/oil gravity drainage as the
primary recovery process in the Natih Field, Petroleum Development Oman
undertook a gas saturation monitoring campaign to determine its
effectiveness. Evaluation based on thermal decay tool measurements
produced secondary gas saturations lower than anticipated from material
balance considerations.
It was reasoned that the limited depth of investigation of the nuclear
tools may have been insufficient to sample formation representative of
the reservoir. In order to resolve this uncertainty a number of wells
were surveyed using the borehole gravimeter as a deep reading formation
density tool. Comparison with original porosity measurements obtained
using conventional devices enabled quantitative gas saturations to be
evaluated. Confidence in the method was obtained by additionally
running the tool across the same formation in a gas reservoir.
Results indicate that the gravimeter can be used to quantify gas
saturations to within a 15% range. The gravimeter has proven effective
in situations where conventional neutron and thermal decay gas
monitoring tools are limited by their depth of investigation.
The accuracy of the method is constrained by the control of distance
between discrete gravity stations, the borehole and cable noise and the
confidence with which the reservoir porosity is known. In low porosity
systems the accuracy is degraded.
As a consequence of the higher gas saturations evaluated using the
Borehole Gravimeter, implementation of full scale gas/oil gravity
drainage in the Natih Field will continue.
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