Reservoir Geochemistry: A Link Between
Reservoir Geology and Engineering?
S.R. Larter, SPE, and A.C. Aplin, U. of Newcastle; P.W.M. Corbett and Neil Ementon, HeriotĆWatt U.;
and Mei Chen and P.N. Taylor, U. of Newcastle
Summary
Geochemistry provides a natural, but poorly exploited, link between
reservoir geology and engineering. We summarize some current applications of geochemistry to reservoir description and stress that, because of their strong interactions with mineral surfaces and water, nitrogen and oxygen compounds in petroleum may exert an important
influence on the pressure/volume/temperature (PVT) properties of
petroleum, viscosity and wettability. The distribution of these compounds in reservoirs is heterogenous on a submeter scale and is partly
controlled by variations in reservoir quality. The implied variations
in petroleum properties and wettability may account for some of the
errors in reservoir simulations.
Introduction
Traditionally, fluid geochemistry has played little role in reservoir engineering practice, with some notable exceptions.1 Since 1985, however, the focus of geochemistry in the petroleum industry has shifted
away from exploration toward reservoir appraisal and production.
This new focus has been termed “reservoir geochemistry” and has
been recently reviewed by Larter and Aplin.2 Because geochemists
deal with both reservoir rocks and their contained fluids, reservoir
geochemistry provides a natural, but underexploited, link between
reservoir geologists and reservoir/petroleum engineers. The dual
aims of this paper are to summarize recent developments in reservoir
geochemistry and to discuss current and potential applications of reservoir geochemistry to petroleum and reservoir engineering.
Current Status
The methods of reservoir geochemistry are similar to those used for
many years by classic petroleum geochemists. Samples are production
and well-test fluids plus materials extracted from reservoir cores or cuttings with organic solvents or deionized water. Reservoir geochemical
studies differ from conventional geochemical studies only in that much
larger sample sets are processed, with up to several hundred reservoir core
extract samples being analyzed in addition to available fluid samples.
Collection and adequate storage of fluid samples is central to effective
reservoir geochemistry, and early baseline studies are desirable if changes
during production are to be identified and understood.
Recent analytical developments now allow, early in field appraisal, the
rapid and inexpensive production of high-resolution, three-dimensional
compositional images of the petroleum column. Larter and Aplin2,3 have
identified three methods that have been developed to characterize petroleum and residual salts rapidly in reservoir core. Two of these techniques
plus some applications are summarized in Fig. 1.
Routine, rapid, inexpensive assessment of levels and bulk composition of petroleum extracted from reservoir cores is now possible with automated liquid chromatographic devices, such as the Iatroscan.4 This approach produces logs of both petroleum saturation (comparable with
electric-log measurements5) and composition, enabling the detection of
such reservoir features as oil/water contacts (OWC’s) and small tar mats.4
This method has complemented reservoir screening by the Rockeval device6,7 and allows routine assessment of variation in oil quality throughout heavy- and light-oil reservoirs. Detection of small tar mats in petroleum reservoirs is critical because these can act as low-permeability zones
or flow barriers (Fig. 2).
Copyright 1997 Society of Petroleum Engineers
Original SPE manuscript received for review 16 November 1994. Paper peer approved 28
October 1996. Paper (SPE 28849) first presented at the 1994 SPE European Petroleum
Conference held in London, 25–27 October.
12
Automated thermovaporization gas chromatography and gas chromatography/mass spectrometry (GC/MS) systems capable of producing high-quality gas chromatographic and gas chromatographic/
mass spectrometric data directly from reservoir cores have
revolutionized the application of molecular geochemistry to the study
of petroleum reservoirs.5,8 These systems allow the production of
biomarker or aromatic-hydrocarbon parameter logs at near-meterresolution at a rate of one data point per hour. Detailed molecular
geochemical logs produced from such systems enable the detection
of compositional steps in petroleum columns, which can be sometimes interpreted as indicating the presence of a flow barrier.9,10 This
interpretation is strengthened by the observation that pressure kicks
sometimes occur across the same geological discontinuity across
which the compositional step is seen.5 The benefit of the geochemical
data is that they can be gathered before repeat-formation-test (RFT)
pressure tests and can be used when deciding on the merits of making
such tests. Correlations between the compositions of produced fluids
with those predicted from preproduction compositional images has
yet to be widely applied but may provide the ultimate test of the validity of production models based on engineering, geological, and
geochemical data.
Determination of the 87Sr/86Sr isotopic composition of salts precipitated by the evaporation of formation water or residual water during core storage11,12 permits the reservoir geochemist to obtain information about the heterogeneity of waters present in the reservoir,
at high spatial resolution. As for petroleum, compositional steps
across geological discontinuities imply that the discontinuity is an effective barrier to fluid flow. Downcolumn trends in the ratio within
the oil leg imply that the composition of water was evolving during
reservoir filling and can be used to suggest detailed filling histories.11
While these new methods have had a major impact on our ability
to characterize petroleum reservoirs, traditional fingerprint gas chromatography coupled with multivariate data analysis has found a new
lease of life, both as a reservoir continuity tool and for detection of
leaking production tubing.13
Variation in water chemistry throughout a petroleum column is increasingly recognized by reservoir geochemists, although this information is not commonly incorporated in reservoir studies. Measurements of the salinities of aqueous fluid inclusions (tiny pockets of
fluid trapped during the precipitation of diagenetic minerals in the
reservoir) in petroleum fields indicate that oilfield water salinities
may vary substantially through time. In one North Sea field we have
studied, fluid-inclusion evidence suggests that salinities varied between 4 and 25 wt% total dissolved solids during the period of field
filling, implying that residual waters trapped in the oil leg also have
variable salinity. Coleman14 has shown that the water trapped within
the oil leg of one North Sea field has a different chemical and isotopic
composition from that in the water leg. The trapped paleowaters have
a salinity of around 25 000 mg/L chloride, while the present-day
formation water contains 60 000 mg/L chloride. These data force us
to reassess the accuracy with which we calculate oil in place (OIP) because this involves the use of resistivity logs through the use of the
practical Archie equation. In this case, assuming that the residual water in the oil leg is identical to that in the water leg would result in a
10% overestimate of OIP.3
In summary, reservoir geochemical methods provide cost-effective
supplements to conventional reservoir appraisal and monitoring procedures and, in some cases, provide alternatives to conventional reservoir test procedures.
SPE Reservoir Engineering, February 1997
Fig. 2—Probe permeameter logs of unextracted, slabbed core
(line), and core-plug permeability logs (dots) obtained from solvent-cleaned core plugs show that, in contrast to the main reservoir sands, the tar mat (defined geochemically) in the reservoir
shows markedly reduced measured permeability before core
cleaning.41
Fig. 1—Some applications of reservoir geochemical methods. (a)
Example of the application of latroscan geochemical logs, showing a log of the concentration of petroleum polar compounds (resins)asphaltenes) extracted from a core in the Ula field; shows a
distinct OWC.4 (b) Log of the polar compound yields in the Ula
and Skaggerak formations of Well 7/12-6 of the Ula field. Several
zones in the Triassic oil column have high absolute yields of polar
compounds. These zones represent small tar mats (“minimats”)
within the oil column that have accumulated on sedimentologically defined features. (c) Geochemical and engineering data profiles through a well in the Eldfisk field. Shown are RFT pressures,
biomarker parameters, and a summary geochemical parameter
(PC1) derived by principal components analysis of a multivariate
biomarker data set. Geochemical data were generated with the
GC/MS system described in the text. Breaks or steps are visible
in all logs between the ED/EE unit boundary and Tor formation
boundary. The geochemical data have detected a barrier in the
reservoir.5
Some Implications for Reservoir
and Petroleum Engineering
Although reservoir geochemistry has been applied to a range of exploration-, appraisal-, and production-related activities, there has
been little geochemical input into field simulation procedures. This
is surprising given that petroleum columns are known to be heterogeneous and that the physical properties of fluids are key inputs to reservoir simulations.
SPE Reservoir Engineering, February 1997
Relationships Between Produced and Reservoired Fluids. Although
petroleum is rich in hydrocarbons, it is the nonhydrocarbons (compounds rich in nitrogen, sulfur, and oxygen) that may hold the key to the
solution of many problems relevant to petroleum production. Petroleum
extracted from North Sea cores contains up to 40% nonhydrocarbons
compared with t25% for the produced oils.2 For example, core extracts
from the Eldfisk chalk reservoir in the North Sea, which is low in both
indigenous organic matter and clay minerals, contain 30 to 40% nonhydrocarbons compared with 10 to 20% in the produced oil.5 The physical
location of these additional nonhydrocarbons (sorbed or not) and their
phase relationships with the produced oils are unclear. Similarly the effect, if any, on the subsurface properties of fluids moveable on production
time scales is unknown. However, if these polar-enriched petroleums are
related to producible fluids, then it would imply that subsurface physical
properties, such as bubblepoints and viscosities, could be significantly
different from the properties derived from analysis of produced fluids.2
Traditionally, discrepancies between reservoir simulations and production histories are ascribed to imprecise knowledge of the properties of reservoir rocks rather than of the reservoired fluids. However, variations and
uncertainties over the true compositions and physical properties of subsurface fluids suggests that variations in fluid properties may also need
to be considered in sensitivity analyses of reservoir performance.
Stoddart et al.5 have recently presented data that suggest that at
least some of the unproduced nonhydrocarbons are strongly sorbed
onto the surface of the reservoir rock. They showed that the distribution of nitrogen compounds (alkylcarbazoles and alkylbenzocarbazoles) in petroleum extracted from the Eldfisk chalk reservoir were
variable on a meter scale, suggesting disequilibrium between mobile
petroleum and petroleum sorbed on reservoir surfaces. This suggests
that compositional heterogeneities in petroleums extracted from
cores are more likely to influence reservoir wettability than the PVT
properties of reservoired fluids. The apparent variability in the composition of core extracts and produced petroleum suggests that both
the physical properties of petroleum and the reservoir wetting state
may vary on both small (pore) and large (e.g., fault-block) scales.
Fluid/Rock Interactions in Reservoirs. It is increasingly clear that
sedimentologicallycontrolled, centimeter-scalegeological structures
control permeability and thus fluid flow in petroleum reservoirs. The
small-scalepermeability structure of rocks is often related to textural
and mineralogical variations. If reservoirs are heterogeneous with respect to wettability (fractional wettability15), it is likely that the small13
Fig. 3—(a) Crossplots of Rockeval S1 and S1/(S1)S2) parameters for the oil leg of a North Sea, Rannoch formation sandstone
reservoir. The proportion of lighter oil (S1—representing material
up to approximately C25) to higher-boiling petroleum (S2) decreases as porosity and petroleum content decrease. (b) Probe
permeameter data for a heterolithic, wavy bedded and rippled
sandstone. The section represents a cored Rannoch formation
section from the North Sea and is part of an oil leg. (c) Semivariograms of the variation of permeability and the Rockeval
S1/(S1)S2) parameter for the interval in b. An increased correlation is suggested with a lag of 0.2 to 0.3 m, tentatively suggesting
that there may be a relationship between the geochemical data
and the permeability data sets at small scale.20
14
scalepetrophysical and mineralogical variations will control distribution of fluid phases. Differences in wettability can be incorporated
into small-scale flow simulations by the use of appropriate relative
permeability functions16 and the field effects identified.
In a single reservoir, there is a commonly observed inverse relationship between reservoir quality (porosity and permeability) and
the nonhydrocarbon content of core extracts.6,9,10,17-19 In many
cases the trends cannot be ascribed to the occurrence of indigenous
organic matter and must represent real variations in the petroleum.
Fig. 3a shows crossplots of Rockeval S1 and S1/(S1)S2) parameters for an oil leg in a North Sea, Rannoch formation sandstone.20
(For reservoirs, S1 is approximately neutral for tC25"; S2 is material uC25.) Although designed for source rock analysis, the Rockeval
S1/(S1)S2) parameter is useful as a monitor of the gross boiling
range distribution of reservoired petroleums. The high petroleum
content in the core (S1 yields of 10 to 30 mg petroleum/g rock) indicate that this is a normal oil leg; the data tentatively suggesting that
the proportion of lighter oil (S1, representing material up to approximately C25) to higher-boiling-point petroleum (S2) decreases as petroleum content, and thus porosity, decrease. At these concentrations
of petroleum, effects from indigenous organic matter will be small.
Fig. 3b shows probe data for a heterolithic, wavy bedded and
rippled sandstone. The section represents a cored Rannoch formation
section from the North Sea and is part of an oil leg.16 The more-thanfour order of magnitude, small-scale permeability variation in the reservoir correlates well with small-scale sedimentological structure in
the core, showing a cyclic variation on a scale of 0.3 m. Fig. 3c shows
semivariograms of the variation of permeability and the Rockeval
S1/(S1)S2) parameter.20 An increased correlation is suggested with
a lag of 0.3 m, tentatively suggesting that there is a relationship between the geochemical and permeability data sets at small scale.
There is much debate over the physical meaning of wettability determinations, but it is generally agreed that the distribution of wetting
and of oil- and water-wetted phases in most reservoirs is complex,
with most reservoirs having mixed wettability.21 Adsorption of organic species from petroleum is widely discussed as a control on reservoir surface state and wettability. Adsorption of nonhydrocarbon
species, such as asphaltenes, resins, or specific nitrogen or oxygen
compounds, onto dry mineral surfaces directly from oil or solvent
solution is easily demonstrated in the laboratory.22-27 With waterwetted surfaces, the adsorption rates are dramatically reduced.
While it is generally assumed that nonhydrocarbons are adsorbed
onto reservoir surfaces in nature, there are few unequivocal observations to support this. Mitchell et al.28 performed surface chemical
analyses of a suite of oil-bearing reservoir cores with varying Amott
wettabilities.Increased oil-wetting indices were observed in samples
the surfaces of which had higher carbon and nitrogen content, implicating adsorption of petroleum species onto the surfaces of the reservoir. Although the relationship between reservoir wettability and
gross surface chemistry was clearly demonstrated and great care was
taken to remove extraneous oil, it is generally difficult to be certain
that stored cores are representative of the subsurface state. This is because resin or asphaltenic material may precipitate onto the reservoir
surfacesduring core recovery and storage, even when special precautions are taken. Cuiec’s29,30 core restoration and wettability studies
provide further evidence for the adsorption of petroleum species onto
water-wet reservoir surfaces on a time scale of months. Both mineralogy and oil composition influenced the adsorption process. Also,
core extracts are often rich in nonhydrocarbons compared with oils
produced from equivalent reservoir intervals.2,17-19,28,31
Li et al.25,26 have provided convincing evidence for adsorption of
nonhydrocarbon species onto petroleum carrier beds (and by implication
reservoir rocks). These authors showed that alkylcarbazoles become fractionated during petroleum migration by selective adsorption onto rock
surfaces. Isomers with no methyl substitution next to the active pyrrole
functional group (e.g., 3,5 dimethylcarbazole) are removed more rapidly
from the petroleum than isomers in which the pyrrole functional group
is hindered by adjacent alkylation (e.g., 1,8 dimethylcarbazole). The fractionation resembles normal phase chromatography and simple calculations indicate that the chemical fractionations observed in migrating petroleums cannot be accounted for by partition of nitrogen compounds
SPE Reservoir Engineering, February 1997
Fig. 4—Distribution of neutral nitrogen compounds in produced
oils (triangles), reservoir sandstone core solvent extracts (open
circles) and related source rocks (solid circles) from a North Sea
sandstone oil-bearing reservoir.32
into water alone but require the involvement of carrier bed surfaces.2 This
remains an area for further work.
Similar fractionations are seen when the nitrogen compound distributions in produced oils and core extract petroleums are compared.
Fig. 4 shows variations in the relative proportions of alkylcarbazoles,
alkylbenzocarbazoles, and alkyldibenzocarbazoles for production
and core solvent extract petroleums from a North Sea sandstone reservoir containing an undersaturated black oil. The core extract petroleums are enriched in alkylated dibenzo- and benzocarbazoles relative to the produced oils, reflecting selective partitioning of nitrogen
compounds onto the solid reservoir surfaces.32
Controls on Distribution of Adsorbed Organic Species in Reservoir: Role of Organic Matter. It is typically assumed that nonhydrocarbons adsorb predominantly onto mineral surfaces because these
are the volumetrically dominant component of most reservoir rocks.
However, the large sorption capacity of solid sedimentary organic
matter (kerogen plus bitumen) for petroleum species33 deserves note
and is discussed later.
Equilibria between petroleum species and reservoir rock components
are not well understood. The actual distributions of wetting and variously
wetted phases cannot be easily examined at the micron scale at which
relevant heterogeneity may exist, but some considerations of the processes that occur during the early filling of a reservoir can be made. Fig.
5 shows a schematic reservoir/carrier rock with possible equilibria between phases. The fluid in contact with both mineral and solid organic
phases in the rock is assumed initially to be water, so that direct contact
between oil and potentially oil-wet phases, such as solid organic matter,15
will develop later once water films have been ruptured.
Equilibrium partition of components between oil phases and waters can be described by a partition coefficient, P, representing the
equilibrium concentration (kg/m3 or g/L) of the component in the oil
phase divided by the concentration in the water phase.
P + CoilńC water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1)
Equilibrium partition of components between waters and solid
phases (minerals or organic matter) can be described by a distribution
coefficient, K, representing the equilibrium concentration of the component on the rock phase (kg/kg or mg/g) divided by the concentration in the water phase.
K + CsolidńC water
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2)
SPE Reservoir Engineering, February 1997
Fig. 5—Pore-scale interactions between oil, water, and solid
phases on a secondary migration pathway. Equilibrium between
the phases is controlled by an oil/water partition coefficient (P);
two distribution coefficients describing equilibrium between oilwet organic matter and oil (Kd2) and between water and water-wet
mineral phases (Kd1); the relative masses or volumes of the four
phases present [oil (Vo ), water (Vw ), oil-wet organic matter (Mr2),
and water-wet minerals (Mr1)].
in m3/ kg or mL/g. K can be determined from an adsorption isotherm.27 So that for oil in equilibrium with a solid phase through a water phase,
CsolidńC oil + KńP.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3)
Macleod et al.34 have suggested that components, such as lowmolecular-weight alkylphenols, are partitioned between petroleum
and water phases. The lowest-molecular-weight alkylphenols, phenol and the cresols, dominate the phenol distributions in oilfield waters, whereas associated oil phases contain more abundant dimethyl
and trimethyl phenols.34 Equilibration of petroleums and waters at
the reservoir pore scale can be expected to occur very rapidly on a
geological time scale on the basis of laboratory studies of mass-transfer coefficients.35 Phenols are thus ideal model species to examine the
controls on the distribution of polar compounds in reservoirs.
Values of K and P for alkylphenols27 and of P values for alkylcarbazoles22 are shown in Table 1. K values for the adsorption of alkylcarbazoles onto solid phases from aqueous solution are notoriously
difficult to determine because the aqueous solubilities of carbazoles
are very low.
The partition coefficients of alkylcarbazoles are several orders of
magnitude higher than those for such species as phenols or carboxylic
acids (Table 1). At the early stages of reservoir filling, it is the morewater-soluble compounds, such as phenols and carboxylic acids, that
would be predicted to be the preferentially adsorbed phases. Alkylated, high-molecular-weight components, such as asphaltenes and
resins, probably control wettability; it is likely that these will have
TABLE 1—DISTRIBUTION PROPERTIES FOR PHENOLS
AND CARBAZOLES
K
Compound
2,5 dimethylphenol
2,3 dimethylphenol
3,4 dimethylcarbazole
1,8 dimethylcarbazole
Brown Coal/
Water
(mL/g)
Illite/Water
(mL/g)
P
Oil/water
990
920
—
—
25
11
—
—
15
13
7 250
26 733
Values were determined at ambient conditions (25°C); P values for phenols were determined at 80°C with a solution-gas-free oil from Eldfisk field. Knaepen et al.40 have indicated that P values are significantly pressure dependant; we are currently measuring
phenol P values under subsurface conditions. Carbazole data are from Ref 26.
15
some cases. Our current work aims to tie together chemical compositional variations in reservoir rocks at small scale with measured and
modeled small-scale flow behavior.
Fig. 6—Fraction of total adsorbed 2,5 dimethyIphenol on solidphase organic matter as a function of sediment TOC. At 2.0%
TOC, about 50% of the phenol is adsorbed on organic matter. The
curve was calculated with the distribution data in Table 1.
very large partition coefficients and thus will be only slowly adsorbed
from the water phase onto solid rock surfaces. More rapid adsorption
will occur if the oil film directly contacts an oil-wetted phase.
The relative masses of components initially adsorbed onto the different phases (minerals and organic matter) from the water phase is
proportional to the relative K values for mineral/water and organic
matter/water multiplied by the mass fraction of each phase. Fig. 6
shows the distribution of 2,5 dimethylphenol between minerals (assumed to have the properties of illite) and organic matter (assumed to
have the properties of brown coal) as a function of total organic carbon (TOC). The curve is calculated from the data in Table 1. The fraction of total adsorbed phenol on the organic matter is plotted vs. TOC
content of the sediment, assuming water to be the contacting phase.
The much larger value for the organic-matter/water distribution coefficient results in preferential adsorption of the phenol onto organic
matter, with most of the phenol being on organic matter at TOC content higher than 2%.
Although the actual distribution of organic matter (i.e., blocky
phytoclasts vs. dispersed grain coatings) will affect the eventual distribution of wetting phases, it is likely that organic matter will exert
an important influence on the distribution of hydrophobic species in
the reservoir. The TOC content of reservoir sands and carbonates varies from t0.1% to u2%. Whether a systematic study of reservoir
wettabilities would show any relationship with TOC content or distribution is unclear, but it is interesting to speculate whether, under appropriate conditions, elevated TOC content in reservoir sediments
may help to preserve water-wet mineral phases by acting as sinks for
hydrophobic petroleum nonhydrocarbons.
Fractional Wettability. Studies at the subseismic to pore scale in reservoirs suggest that there are variations in fractional wettability controlled by petrophysically inferred mineralogical variations.16,36,37
Heterogeneous distributions of nonhydrocarbons at the large-faultblock or reservoir-compartment scale (hundreds to thousands of meters) might also result in different fractional wettabilities.5 Fractional
wettability at a hierarchy of scales is predicted on the basis of the scaling observed in sedimentary rocks and is implicated in a variety of
capillary trapping mechanisms proposed to account for residual oil
distributions in waterfloods.38,39 Detailed studies linking reservoir
geological, engineering, and geochemical protocols are required to
verify these concepts, to determine the scales at which fractional wettability varies, and to assess its importance in assessment of residual
oil distributions and improved petroleum production strategies.
To date, useful bulk correlations of oil/mineral composition and
wetting ability have not been achieved,15 and the analytical techniques appropriate for the characterization of adsorbed phases in
rocks at relevant scales are not yet routinely used or even available in
16
Conclusions
Reservoir geochemistry is a cost-effective reservoir management
tool. Proven applications to reservoir engineering include detection
of reservoir continuity problems, location of fluid contacts, detection
of tubing leakage, and location of tar mats (see Ref. 2 for a review).
Evidence that small-scale geological features do exert a control on
the subsurface properties of petroleum, coupled with research on
nonhydrocarbon distributions in reservoirs, strongly suggests that
some of the dispersion in reservoir simulations may be related to variations in fluid properties rather than to the traditionally determined
rock properties (porosity, permeability). That petroleum and waters
in petroleum reservoirs are compositionally heterogeneous at a range
of scales is certain. Whether these variations critically affect current
reservoirengineering practices is suspected but not proved. Reservoir
geochemistry has the potential for improving our understanding of
rock/fluid interactions, enabling engineers to address the issue of residual oil in a more systematic fashion.
Nomenclature
C+ concentration, g/L or kg/m3
k+ permeability, L2
K+ distribution coefficient, mL/g or m3/kg
P+ partition coefficient
Acknowledgments
We thank Maowen Li and Gordon Macleod for evolution of the concepts on partitioning of petroleum species. U. of Newcastle thanks the
sponsors and supporters of our reservoir geochemical studies carried
out since 1989 [Phillips Petroleum, Unocal, Saga Petroleum, Statoil,
BP, PSTI, NERC, European Community (EC) Thermie Program.
NRG Industrial Liaison Program]. This review was compiled as part
of a technology demonstration carried out under the EC Thermie Program. Heriot-Watt U. thanks BP for provision of the Rannoch formation material. P.W.M. Corbett is the Elf lecturer in reservoir evaluation
and thanks Elf Production Geoscience for financial support. The
manuscript was prepared by Yvonne Hall and the figures by Christine
Jeans and Barbara Brown.
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SI Metric Conversion Factors
ft 3.048*
°F (°F*32)/1.8
md 9.869 233
psi 6.894 757
*Conversion factor is exact.
E*01 +m
+°C
E*04 +mm2
E)00 +kPa
SPERE
Steve Larter is Professor of Geology, U. of Newcastle. Andy Aplin
is Head of Fossil Fuels and Environmental Geochemistry Inst. U. of
Newcastle.Pat Corbett is Elf Lecturer, HeriotĆWatt U. Neil Emerton
is a researcher at HeriotĆWatt U. Mei Chen is a research associate
at U. of Newcastle. Paul Taylor is a researcher at U. of Newcastle
and is currently with Unocal Corp. in Texas. Photographs are unĆ
available.
17