oil tracers services development geochemistry reservoir continuity video

8/9/2019 Oil Tracers Services Development Geochemistry Reservoir Continuity Video

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OilTracersServicesDevelopment GeochemistryReservoir Continuity Video

Assessing Reservoir Compartmentalization

Using Oil GeochemistryIn this article, "reservoir continuity" refers to the absence of vertical fluid flow barriers

between two sampling points within a single well (vertical continuity) and/or the absence of

lateral continuity barriers between two sampling points in discrete wells (horizontal

continuity). Similarly, "reservoir compartmentalization" refers to the presence of fluid flow

barriers between two fluid sampling points.

For many years, a variety of companies have applied oil geochemistry (oil fingerprinting) to

reservoir continuity assessment in a diverse range of geological settings (including a wide

range of field sizes, structural environments, reservoir lithologies, and oil types). As

demonstrated by numerous published and unpublished case studies, petroleum geochemistry provides an effective tool for identifying vertical and lateral fluid flow barriers within oil and

gas fields. The technique is especially useful because it provides an independent line of

evidence for evaluating the reservoir continuity implications of other data types (data such as

RFT pressures, pressure decline curves, oil-water contact depths, fault juxtaposition or Allen

diagrams, etc.).

At OilTracers, we assess reservoir compartmentalization by integrating geochemical,

geological, and engineering data to determine the sealing capacity of potential no-flow

barriers. Oil geochemistry typically provides a very inexpensive key to interpreting

ambiguous geological and/or engineering information. This approach is described below.

Description of the Oil Fingerprinting Approach for

Assessing Reservoir Continuity

In a series of five papers published over a 14-year period, scientists from Chevron described

and demonstrated an oil fingerprinting technique for assessing reservoir continuity based on

integration of oil geochemistry with geological and engineering information (e.g., Slentz,

1981; Kaufman et al., 1990; Hwang and Baskin, 1994; Hwang et al., 1994; Sundararaman et

al., 1995). Variations on this technique are currently used by a variety of oil companies (as

detailed in the case studies). The technique put forward by these five papers is described inthis section. The individual published case studies that illustrate the use of oil geochemistry

in reservoir continuity assessment are described on our case studies page.

The approach described in the five papers mentioned above is based on the proposition that

oils from discrete reservoirs almost always differ from one another in composition. The

technique assesses whether or not two oils are in fluid communication by comparing for each

oil the relative abundances of the several hundred "inter-paraffin" peaks identifiable on a

whole oil gas chromatogram or "GC". Inter-paraffin peaks are those compounds that elute

from the GC between the normal-paraffins. The patterns for each sample are compared as

follows:

1. Corresponding inter-paraffin peaks are identified in all samples.

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2. For a given sample, several hundred ratios of closely spaced inter-paraffin peaks are

compared with the corresponding ratios in the other samples.

3. The ratios that differ the most between samples are identified.

4. Values for these ratios for each sample are plotted on polar or "star" plots. On such

diagrams, the composition of each oil is represented by a "star" in which each point

on the star corresponds to the value for a given peak ratio.

Star plots constructed in this way maximize the apparent differences between samples. By

stripping away what samples have in common and focusing on how they differ, such plots

allow discrete groups of samples to be readily, visually identified. To arrive at an assessment

of reservoir compartmentalization, these data must be integrated with any other available and

relevant geological and/or engineering information (such as fault distributions, fault throws,

fault shale/sand gouge ratios, lateral changes in reservoir lithology, RFT or DST pressure

data, pressure decline curves, oil-water contact depths, etc.). Commonly, in oils which are in

fluid communication, none of the several hundred inter-paraffin compound ratios will differ

by more than 10% from the corresponding ratios in oils with which they are in fluid

communication. In contrast, when a lack of fluid communication exists between two samples,a large number of ratios (typically >10) in one oil will differ by >10% from the

corresponding ratios in the second oil. These ratios will commonly be distributed throughout

the C8-C20 range, and will not be restricted to a narrow portion (e.g., a one or two carbon

number range) of the chromatogram (differences restricted to a narrow portion of the

chromatogram are a symptom of sample contamination with substances such as drilling

additives and typically do not imply reservoir continuity barriers). The analytical

reproducibility for ratios of closely spaced inter-paraffin peaks is typically 1-3% (Kaufman et

al., 1990). As the number of ratios with significant differences between the samples

decreases, the geochemical case for lack of communication becomes less strong. Exceptions

to these guidelines exist in cases of certain thick, gravitationally segregated oil columns,

where reservoir discontinuities must be identified from discontinuities in otherwise

gradational changes in composition with depth. The C8 to C20 molecular weight range on the

GC is typically the most diagnostic range for reservoir continuity assessments. The

distribution of lower molecular weight compounds is usually not compared, since they can be

more readily affected by evaporative losses during sample handling.

The star diagram approach for assessing fluid communication is effective for comparing GC

data for a small number of samples. As the number of samples increases, the number of

possible compartments increases, and a single star diagram may no longer be able to

summarize all the compositional variability between the samples (e.g., the dozen GC peak

ratios that differ most between oils A and B may be different than the dozen ratios that differ most between oils A and C which may differ from the ratios that best separate A from D).

Therefore, the samples compared on a given star diagram are chosen so as to answer a

specific question, such as: "is this fault sealing?" Only the samples relevant to answering that

question should be included on that diagram. Therefore, compositional variability in large

sample sets may have to be evaluated with several star diagrams in which each diagram is

designed to answer a different, specific question about the reservoir architecture. To make a

general comparison of GC data for a large number of samples, the GC peak ratio data used to

construct the several star diagrams can be compared statistically and used to construct a

single cluster analysis diagram (e.g., Hwang and Baskin, 1994).



The differences observed among the star diagrams for a group of samples are the result of

compositional differences among the samples, and these compositional differences exist for

one or more of the following reasons (e.g., Hwang et al., 1994):

1. The oils may be derived from different source rocks, or may have differing

contributions of oil from multiple source rocks. (Note on terminology: a "source rock"has nothing to do with the reservoir rock that contains the oil in the oil field; the

source rock is the rock that generated the oil that later migrated into the reservoir

rock. The source rock may be 10's of miles away from the oil field). Oils derived from

different source rocks differ in composition. Since oils from different source rocks

have different times of generation and/or different migration paths, the presence of

more than one source rock in a basin may cause different reservoir compartments to

fill with different mixes of oil from the respective sources. For example, oil in

Prudhoe Bay is known to be a mixture of petroleum from three source rocks of very

different age (Masterson et al., 1997; 2001), and source variations are therefore a

likely cause of the compositional differences among oils from discrete fault blocks in

that field. A second example can be found in Schoellkopf et al. (1998 and 2000)where the authors discuss variations in charges from three different source rocks in

offshore Cabinda, west Africa; those source variations result in both lateral and

vertical variations in oil fingerprints within and among the offshore oil fields in that

area.

2. The oils may be derived from the same source rock but at a different level of thermal

maturity. Oil which a source rock generates at a given time differs slightly both from

subsequently generated oil and previously generated oil due to continuous, subtle

changes in the maturity of the source rock and changes in precisely which part of the

source rock is in the oil window.

3. Post-emplacement alteration processes. Identically sourced oils that reside in separate

reservoir compartments may have had a different exposure to processes that affect oil

composition after the oil enters the reservoir (e.g., processes such as biodegradation,

water washing, and evaporative fractionation).

4. Filling history considerations. Since no two compartments are of identical geometry,

and since no two compartments have exactly the same filling history, it is difficult to

achieve precisely the same composition in two separate compartments, even with oil

from the same source.

An important aspect of this oil fingerprinting approach is that a given star diagram can only

be constructed from data acquired from the same instrument within a several day analytical

period. For a given diagram, data cannot be compared between instruments becausedifferences in analytical conditions (e.g., different GC columns, different carrier gas

pressures, or different column ages) will cause subtle differences in peak resolution that may

show up as large differences in the peak ratios. Data collected from the same instrument

several months apart also cannot be compared on a single diagram, since analytical

conditions may have changed during the analysis of the intervening samples (conditions such

as GC column characteristics).

Assessing Reservoir Continuity in a Gas Accumulation

A similar approach is used to assess continuity in gas accumulations. However, a greater

range of geochemical analyses may be brought to bear, including:



• Gas chromatography data for the gas condensates (with the data being processed

using the inter-paraffin peak ratio method described above for oils)

• Gas composition (e.g., relative abundance of each gas present, including trace gases,

such as helium)

• Isotopic composition of carbon and/or hydrogen in specific gas species (methane,

ethane, CO2, etc.)• Isotopic composition of carbon and/or hydrogen of the paraffins in the gas condensate

Case Studies

Case studies in which geochemistry is used as part of a reservoir continuity assessment

include: Slentz (1981), Kaufman et al. (1990), Lindberg et al. (1990), Hwang and Baskin

(1994), Hwang et al. (1994), Sundararaman et al. (1995), Ross and Ames (1988), Nederlof et

al. (1994; 1995), Westrich et al. (1996; 1999), Noyau et al. (1997), Kaufman et al. (1997),

Edman and Burk (1999), Smalley et al. (1992; 1994), England et al. (1995), Smalley and

Hale (1996), and Halpern (1995). A summary of some of these case studies is availableelsewhere on this site.

Additional Considerations When Applying Oil

Fingerprinting to Continuity Assessment

Throughout the literature on oil fingerprinting, a common caveat is that oil fingerprinting is

most successful as a technique for assessing reservoir continuity when it is applied in

conjunction with other lines of evidence, such as:

• RFT/ DST pressure data

• Pressure decline curves

• Dew-point calculations (for gas continuity studies)

• Reservoir descriptions (from core, cuttings, and log data)

• Oil-water contact depths

• Fault sand/shale gouge ratios

• Fault juxtaposition (Allen) diagrams

This caveat to integrate disparate data types applies to all lines of evidence for reservoir

continuity assessment. This is true because these data types are independent of one another,

and hence provide valuable crosschecks. Crosschecks are important because every technique

is subject to potential pitfalls. Some such potential pitfalls associated with the application of

oil fingerprinting to assessment of reservoir continuity are discussed in the sections below.

Very Unusual Filling Histories







Very unusual scenarios could exist where nearly identical oils are found in separate

compartments. For example, two pools could have the same composition if they were

originally in communication, but then achieved separation do to a poor seal causing a

reduction in overall pool size (creating two pools out of one). Alternatively, tilting of a large,

homogenous pool could conceivably cause oil of a given composition to spill into two

neighboring traps. Several other such scenarios can be imagined. As a result, to interpretreservoir continuity, we integrate geochemical information with what is known about the

geology and geological history. An example of unusual filling history was presented by

Patterson et al. (2003) where an oil field located in the near-shore Nigerian swamp consisted

of two stacked reservoirs bisected by a fault. Oil fingerprints, water chemistry, and

engineering data suggested that gas and then oil had leaked from the deeper reservoir into

selective areas of the shallow reservoir due to poor fault seal and fault-induced juxtaposition

of the two reservoirs.

Very Young Reservoirs

At a recent conference, a case study was presented (Beeunas et al., 2000) in which oil

reservoired in a very young sandstone (the reservoir rock was deposited on the 1.86 million

year sequence boundary) was found to have heterogeneous oil fingerprints within a single

compartment. The speaker pointed out how very unusual this situation was, and pointed to

the extremely recent timing of the oil emplacement based on burial history and thermal

maturation models as the cause for the heterogeneity (generation possibly extends to the

present). In cases such as this, where the charge is very recent, care should be used in

interpreting the reservoir continuity implications of differences in oil fingerprints.

Gravitationally Segregated Oil Columns

Very thick oil columns are often gravitationally segregated (e.g., Creek and Schrader, 1985).

Perhaps the most obvious expression of such segregation is a progressive increase in API

gravity with decreasing reservoir depth. Such segregation often does not change the oil

fingerprint substantially (Kaufman et al. 1990), because compound ratios selected for the star

diagrams are of closely spaced inter-paraffin peaks, and the similar molecular weight of such

closely spaced compounds greatly reduces the effect of gravitational segregation on the peak

ratio values. Nonetheless, we have sometimes observed progressive changes in peak ratios

with depth in very thick oil columns (McCaffrey et al., unpublished data). In such cases,

vertical continuity barriers can best be identified by plotting compound ratio values vs. depth

and then inspecting these plots for discontinuities in an otherwise gradual trend. In other words, if a compound ratio is changing progressively with depth, and this progressive change

is broken by a sudden, large change in value across a potential barrier, then that large change

would be evidence for that feature being a fluid-flow barrier.

Actively Biodegrading Oil Reservoirs

In actively biodegrading oil accumulations, biodegradation typically occurs at the oil/water

contact (e.g., Dahl and Speers, 1985; Larter et al., 2006). Mixing processes are commonly

unable to homogenize the perturbation in composition being introduced by this

biodegradation process, and, as a result, a compositional gradient away from the oil-water

contact may develop in the oil column. In such cases, vertical or lateral compartment

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boundaries are revealed as vertical or lateral discontinuities in the biodegradation-induced

compositional gradient.

Very Tight Reservoirs

McCaffrey et al. (1996) discussed extreme variability in oil fingerprints within a very

shallow, very tight reservoir (diatomite rock, <1 md permeability) in the Cymric Field, Kern

County California. That reservoir contained very heavy (12o API), very viscous oil that may

have been undergoing active biodegradation right up until the initiation of the current steam

flood. The oil fingerprint data reported by McCaffrey et al. (1996) may initially seem to be at

odds with the assertion that oils within a reservoir have nearly identical fingerprints.

However, there is no conflict here at all. In very tight reservoirs, the concept of "reservoir

continuity" is not applicable: the whole oil-bearing unit can be thought of as one giant no-

flow barrier. In fact, the only way that the Cymric field produces oil at all is by steam-

fracturing the diatomite to create permeability. Therefore, in an engineering sense, the

"reservoir" is CREATED by the fracturing process: the body of rock that eventually producesinto a Cymric well is defined by the artificial fracturing process used to stimulate that well.

Compositional variability in this field has no relevance at all to the oil fingerprinting

technique for assessing reservoir continuity: there is no reservoir continuity in a very tight

reservoir.

Confusion Resulting From How the Term "Reservoir" is

Used

The term "reservoir" is used differently by different authors, and, in some papers, the sense in

which the term is being used is not immediately obvious. As a result, statements in some publications may initially seem to be at odds with the oil fingerprinting technique described

above. However, in actuality, many of these apparent conflicts stem solely from the way the

term "reservoir" is being used.

When discussing the oil fingerprinting technique, the term "reservoir" refers to an oil-bearing

body of rock that is in fluid communication throughout its lateral and vertical extent. In this

usage, a "reservoir" does NOT correspond to a stratigraphic unit. For example, "Oil Field A"

may contain an oil-bearing stratigraphic unit called the "Alpha Sandstone." This sandstone

may be cut by two sealing faults that divide the Alpha Sandstone into three compartments. In

the sense in which "reservoir" is used with regard to oil fingerprinting, "Oil Field A" contains

THREE reservoirs: one corresponding to each compartment. Although there is only onestratigraphic unit (the Alpha Sandstone) there are three reservoirs, because that sandstone is

compartmentalized into 3 units that are not in communication with each other. This use of the

word "reservoir" is consistent with how a production engineer uses the term. Geologists,

however, may be prone to write: "The Alpha sandstone is the reservoir in Oil Field A",

implying that there is one, not three reservoirs. As a result, when some authors report oil

fingerprint variability within a "reservoir", they actually mean within a stratigraphic unit.

That stratigraphic unit may consist of several compartments, each of which is internally

homogenous with respect to oil fingerprints. Therefore, the fingerprint variability they are

reporting is BETWEEN compartments, not within compartments.



Confusion Over the Terms "Composition" and

"Fingerprint"

The "composition" of an oil refers collectively to the absolute concentrations of each

compound in the oil. The term "oil fingerprint", as used with regard to the techniquedescribed is this article, refers to the relative abundances of closely spaced peaks on an oil

GC (i.e., the values for ratios of closely spaced peaks). As noted by Kaufman et al. (1990):

"The term "uniform fingerprint" is not to imply uniform hydrocarbon composition. There are

many factors that may affect the composition of oil within a pool, including gravity

segregation (Creek and Schrader, 1985), degradation at the oil/water contact (Dahl and

Speers, 1985), and migration effects (England et al., 1987). These effects can usually be

normalized by using ratios of peaks corresponding to compounds of similar, if not identical,

molecular weight in the n-C7+ region of the chromatogram"

No one disputes that the composition of oil in a very thick compartment can change withdepth as a result of gravitational segregation. As noted in the previous section, perhaps the

most obvious expression of such segregation is a progressive increase in API gravity with

decreasing reservoir depth. However, as Kaufman et al. (1990) note, such segregation often

does not change the oil fingerprint substantially because compound ratios selected for the star

diagrams are of closely spaced inter-paraffin peaks, and the similar molecular weight of such

closely spaced compounds greatly reduces the effect of compositional variations (such as

gravitational segregation) on the peak ratio values. Therefore, when reading the literature, it

is important to distinguish between what the authors mean by "fingerprint" vs. "composition".

Figure 1: Integration of Geology, Engineering, and Oil Geochemistry Data Reveals Field

Architecture

This figure provides a simplified illustration of how oil geochemistry can be used to assess

reservoir continuity. The sampling points of five oils (black boxes) in three wells are shown.

The star plots of the five oils are depicted next to their sampling locations. Continuity of sand

I between Wells B and C is suggested by the identical star plots for the sand I oils from those

two wells. No communication between sands I and II in Well B is suggested by the different

star plots for the Well B oils from those sands. Fault X is sealing where sands I and II are

juxtaposed, since sand II and sand I oils from Wells A and B, respectively, have different star

plots. Remember: geochemical data should be integrated with the geological, and engineering

data (e.g., RFT pressure data, pressure decline curves, oil/water contact depths, GOR values,

etc.) before arriving at a reservoir continuity interpretation.

Anthropogenic Chemical Tracers

The oil fingerprinting technique for assessing reservoir communication discussed in this

article is entirely different than the technique of using anthropogenic chemical tracers as tools

for assessing reservoir continuity. Anthropogenic chemical tracers are compounds that are

added to injection fluid and are monitored in the production of associated producing wells in

order to assess reservoir continuity between the injection well and the producing wells (e.g.,Dugstad et al., 1999; Ali et al., 2000; Chopra and McConnell, 2004). In contrast, the



approach discussed here uses naturally occurring compounds in the oil as natural tracers for

assessing reservoir communication.

For more information on reservoir continuity assessment, or to discuss a specific project, e-

mail us at [email protected], or call us at (214) 548-9169.

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