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Exploration
Play Analysis
from a
Sequence
Stratigraphic Perspective
By
John W. Snedden1, J. F. (Rick) Sarg1, and Xudong (Don) Ying2
Search and Discovery Article #40079 (2003)
1ExxonMobil Exploration Company, P.O. Box 4778, Houston, Texas 77210-4778 ([email protected]; [email protected])
2ExxonMobil Upstream Research Company, P.O. Box 2189 · Houston, TX. 77252-2189 ([email protected]).
Abstract
Examination of exploration drilling histories for many different global basins indicates a counter-intuitive temporal and spatial pattern in the way hydrocarbons are sometimes discovered. Conventional wisdom holds that for any given basin or play, a plot of cumulative discovered hydrocarbon volumes versus time or number of wells drilled usually show a steep curve (rapidly increasing volumes) early in the play history and a later plateau or terrace (slowly increasing volumes). Such a plot is called a creaming curve, as early success in a play is thought to inevitably give way to later failure as the play or basin is drilled-up. It is commonly thought that the "cream of the crop" of any play or basin is found early in the drilling history.
By examining plays or
basins with sufficiently long drilling histories and range of reservoir
paleoenvironment and trap types, one actually finds two or three "terraces" to
the creaming curve. The first string of successes in a given basin usually
corresponds to exploitation of the highstand systems tract or sequence
set
reservoirs developed in updip structural traps. These reservoirs are typically
marginal to shallow marine "shelfal" deposits, laterally continuous but lacking
internal sealing facies and are seldom self-sourcing. The second or third
terrace in the creaming curve usually involves the lowstand reservoir component
(systems tract or
sequence
set), which is often developed in downdip deepwater
or slope paleoenvironments. Transgressive (systems tract or
sequence
set)
reservoirs, typically shallow marine shelfal sandstones that are sometimes
self-sourced, are variably developed and may or may not occupy the second
terrace of the creaming curve. These trends hold true for both 2nd-order
(3-10 my) and/or third-order (1-3 my) stratigraphic cycles, depending upon the
scale of the basin or play.
This analysis
fits
well
with the definition of an exploration play provided by Magoon and Sanchez
(1995): a fully developed play is the simple volume difference between the
petroleum system capability and the current discovered hydrocarbon volumes
(commercial or not). Where the difference is large, either the petroleum system
has significant leakage problems (e.g., Barents Sea Mesozoic play) or the
lowstand systems tract or
sequence
set has not been fully exploited.
Examples supporting these ideas are drawn from several global basins (Gulf of Mexico Miocene, Norway Upper Jurassic, Mahakam Delta, Texas Wilcox). Case studies demonstrate how critical elements of exploration risk shift from trap and seal in highstand plays to reservoir and source in lowstand components of these plays.
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
uWilcox play, Lower coastal zone, Texas uPlio-Miocene play, Kutei Basin, Indonesia uCreaming curve as predictive tool
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IntroductionOne of the most critical tasks faced by petroleum industry geoscientists relates to the decision to enter into an exploration play or basin. Equally important is the timing of entry and if, unsuccessful, the timing of an exit from the play or basin. These judgments are as important as the decision to drill individual prospects in a play or basin (Brown and Rose, 2002).
Explorationists use
a variety of methods to evaluate oil and gas plays. One of these is the
“creaming curve”, basically a graph of cumulative discovered hydrocarbon
volumes versus time or number of wells drilled (Figure 1). This type of
plot, formalized by Meisner and Demirmen (1981), is used to forecast
future exploration success in a petroleum province by determining if
discoveries are on a general rising trend (immature play) or a constant
trend of cumulative volumes (mature play). Implicit in this One example of the diminishing effectiveness of exploration effort with advancing drilling is illustrated by the Middle Jurassic play of the United Kingdom, Norway, and Denmark (Figure 2). The creaming curve is quite steep in the years 1970 to 1980 when the giant oil fields of Brent, Beryl, Statfjord, Oseberg and others were discovered. Hydrocarbons are primarily trapped in large structural closures and non-marine to shallow marine sandstone reservoirs of the Brent Group (Johannessen et al., 1995). Success in this Middle Jurassic play slowed after 1980 as indicated by the plateau in the creaming curve. The first eight years of exploration in this play yielded about 77% of the reserves, on a estimated ultimate reserve basis (Berge, 1997). However, this simple creaming pattern of a rising limb (immature phase) and a long, final plateau (mature phase) is not universal. Some plays exhibit more complex histories of drilling success, with multiple rising limbs and plateaus, suggesting that other factors are at work (Figure 3).
One could explain more complex play histories from a
The
The second or third pair of rising limbs and plateaus (Figure 4) often
come from discoveries in lowstand systems tract (LST) or lowstand
After providing definitions of key terms, this paper will describe several
exploration plays which display more complex histories on creaming curve
graphs. Definitions
The creaming curve method of
In relatively large
petroleum provinces like the U. S. Gulf of Mexico Basin, one could argue
that exploration plays like the Miocene trend are actually assemblages of
several plays, each with unique characteristics of reservoir, entrapment,
etc. However, we have stayed at a fairly general level when considering
exploration plays in order to meet the original criteria set forth by
Meisner and Demirmen (1981) for creaming curve
Many of the plays
discussed in this paper cover thick stratigraphic intervals where
interpretations are made at the 2nd-order level, as per the
definitions of Mitchum and Van Wagoner (1991). In these thick successions,
stacked packages of sequences make up individual highstand, transgressive,
or lowstand Miocene Play, Gulf of Mexico, USA
The Miocene play of the
Gulf of Mexico clearly meets the criteria for creaming curve
Stratigraphic subdivisions of highstand, transgressive, and lowstand
systems tracts or
·
Progradational: highstand systems tract (HST) or highstand
·
Retrogradational: transgressive systems tract (TST) or transgressive
·
Submarine Fan: Lowstand systems tract (LST) or lowstand · Aggradational: HST-HSS or LST-LSS
While the aggradational classification spanned several
The Gulf of Mexico Miocene play spans about 15 to 18 million years of
geologic time, thus it encompasses at least one 2nd-order
cycle. While the play can be discussed from the perspective of the
The Miocene play displays the pattern expected from progressive
exploration of a play with reservoirs in multiple The Miocene TSS has not really yielded significant hydrocarbon volumes in the Miocene, as it is normally quite shale-prone in all stratigraphic levels in the high subsidence regime of the Gulf of Mexico (Armentrout, 1991; Diegel et al., 2001). Thinning landward in these passive margin settings often makes the embedded TST's look eroded, though this apparent truncation is clearly a function of the seismic resolution (Mitchum et al., 1994). However, the cumulative discovery curve for the Miocene play shows an abrupt increase beginning in the 1980’s as the deepwater sandstones of the LSS were penetrated. Beginning in the early 1980’s, there is a pronounced increase in discovered volumes as reservoirs of the paleo-deepwater slope channels, and basin floor amalgamated channels and sheets were drilled in progressively deeper water (Lawrence, 1997). With the Thunder Horse field discovery in 1999, cumulative discovered volumes for the LSS component of the Miocene play now exceeds that of the HSS component. Thus, the suggested pattern of multiple rises and plateaus is quite apparent in the creaming curves for the three stratigraphic components of the Gulf of Mexico Miocene. The HSS plateau is followed by the LSS rising limb, which apparently is still in the “immature” phase of exploration (definition of Meisner and Demirmen, 1981). Alternatively, one could argue that the Thunder Horse discovery could be a different play type (turtle structure) than many of the other deepwater Miocene fields (salt mini-basin traps of Lawrence, 1997). However, the number of wells targeting Thunder Horse type traps is relatively small, and these are plotted on the same plot, following the guidelines of Meisner and Demirmen (1981).
It is illuminating to consider the causes for the mid-1980’s jump in
exploration success in the LSS component of the Miocene play. This
increase in discovered volumes was preceded by major enhancements in the
water depth capability of exploration drilling and deepwater producing
technology (Bourgeois et al., 1998). Other influences include
significant improvements in seismic imaging, changes in offshore lease
sale processes, and, importantly, advances in Upper Jurassic Play, Norway
The Upper Jurassic
of the Horda Platform and adjacent Norwegian Sea of Norway is a
Hydrocarbons in the
Upper Jurassic of the Troll Field (West and East) are trapped in a large
fault-bounded, horst structure (Figure 8). A large gas column and smaller
oil column extends across a stacked series of HST and TST shallow marine
sandstone reservoirs of the Sognefjord and Fensfjord Formations (Gibbons
et al., 1993). This composite succession of HST’s and TST’s forms a
classic Highstand
A smaller (by
comparison) discovery came a few years later in 1984 at the Draugen Field,
which reservoired in similar age sandstones on the Trondelag Platform much
further north (Figure 7). Unlike Troll Field, Draugen Field does not
exhibit a large pronounced structural closure. A stratigraphic component
for entrapment is provided by the lateral pinchout of the sandstone
reservoirs (Provan, 1993). Sandstones are also shallow marine in origin,
with obvious shelfal indicators like ammonite shells and marine dinocysts
(Van der Zwan, 1989). The Draugen Field thus represents the second of the
three
The third tier to
the Upper Jurassic Play came over twenty years later in 1996, with
discovery of the Fram Field in Block 35/11 (Figure 7). Initial tests of
the Sognefjord Formation reservoirs yielded over 4400 BOPD with associated
oil (AAPG Explorer, 1996). Sandstone reservoirs are interpreted to be
paleo-deepwater high-density turbidites deposited in a lowstand submarine
fan system (S. Setterdahl, personal communicaton). The discovery was made
with the eighth
The discovery of the
Fram Field proved that a third component to the Upper Jurassic play exists
and additional drilling has pursued this component. Thus, this play fits
the Wilcox Play, Lower Coastal zone, Texas, USA
The Wilcox Play of
Texas also has a long exploration history, extending as far back as 1942
(Figure 9). Both oil and gas are found in the Wilcox, but gas dominates,
probably due to source rock type and maturity, and the tendency for
reduced permeability in more deeply buried reservoirs (Kosters et al.,
1989). Like several plays discovered previously, the first rising limb of
the creaming curve is represented by fields developed in fluvial to
marginal marine sandstones in The second set of discoveries in the Wilcox play of Texas began in the mid-1960’s with discovery of the Laredo Field (1.0 TCFG OGIP) in South Texas. Laredo and other fields in the immediate area produce from a transgressive succession of shallow marine sandstones known informally as the “Lobo” series. Lobo sandstones harbor gas in a combination structural-stratigraphic trap with small scale faults and sealing by unconformities at the upper and lower Lobo levels (Figure 11). These subtle traps are typical of the second tier or “transgressive” component of the creaming curve. The third tier of the Wilcox came over 15 years later as the downdip (lowstand) Wilcox component began to be exploited by South Texas majors and independents (Figure 9). Deeper drilling and higher gas prices in the late 1970’s led to discoveries in the Seven Sisters, East (Duval County) and Fandango Fields (Zapata County). These fields are different in terms of structural style: thick growth wedges developed on the downthrown side of major listric faults (Edwards, 1981). Structural closure is provided by rollover into the faults (Stricklin, 1994).
However, detailed
stratigraphic Follow-up to the downdip Wilcox discoveries occurred in the middle 1990’s with major gas finds like the Bob West Field in Zapata and Starr Counties (Jones, 1994), but these basically follow the same trap and reservoir type as the Seven Sisters East Field. Since the first plateau in the 1950’s, about 6.0 TCFG (OGIP) has been discovered in the Wilcox play.
One key difference
between the Wilcox play and other examples discussed thus far is the fact
that Wilcox reservoirs, even in the lowstand Plio-Miocene Play, Kutei Basin, Indonesia
A final example of an exploration play with a history following the
Exploration on the Kutei Basin onshore began nearly 100 years ago (Figure 3). Significant large discoveries in this area occurred in the 1960’s and 1970’s in simple anticlinal closures within HSS fluvial and deltaic reservoirs of the paleo-Mahakam (Duval et al., 1992). Fields like Badak, Tunu and the Handil-Tambora-Nilam trend are all large structural traps, which are required in order to hold hydrocarbon columns in this very sand-prone Miocene section delta (Huffington and Helmig, 1980). However, exploration success diminished after the identification of Tunu field in 1977. Nearly ten years passed before Total found hydrocarbons in the TSS sandstones at the Sisi-Nubi Field area in 1986 (Duval et al., 1992). However, established local operators were reluctant to drill farther basinward because of several dry holes and concerns about distance from established coastal-plain coaly source rocks of this Type III petroleum system. However, an alternative view suggested that the “rim” of dryholes on the outer shelf simply defined the basinward shale-out of the HSS and TSS and were not representative of the LSS present (Snedden et al., 1996a). In fact, it was argued that an incompletely explored lowstand component was present, one that had a high chance of success if the adequate source rocks were present.
With limited Following completion of detailed studies and recommendations to drill, and in partnership with a new operator (Unocal), a series of wells were drilled in deepwater regime of the Kutei Basin and adjacent Makassar straits. Recent successes in the Merah-Besar, Seno, and West Seno in the Makassar PSC have proven the presence of both adequate transported terrestrial organics (Dunham et al., 2000) and reservoir in the lowstand component of the Plio-Miocene play (Saller et al., 2000). Using the Creaming Curve as a Predictive Tool
As the Kutei Basin
example superbly demonstrates, there is some utility to recognizing the
potential for a second or third “tier” to a given exploration play. In
fact, this approach follows the philosophy of Magoon and Sanchez (1995): a
complementary play can be inferred from mapping the total petroleum system
and subtracting the discovered fields and non-commercial accumulations. If
the difference is large or whole elements (e.g., systems tracts or
One way to identify
an under- or unexplored play is to compile field statistics by systems
tracts or
Examination of the
same 32 onshore plays indicates that in less than a third of these produce
from more than two systems tracts or
In fact, Kosters
et al. (1989) has estimated that 20 TCFG of undiscovered, recoverable
gas reserves remains in the Lower coastal province of Texas. A rough
estimate of the partitioning of reserves suggests that most of the future
potential lies in the lowstand systems tracts or Understanding the natural progression of an exploration play can facilitate decision-making on company resource (manpower and skill set) allocation. Critical risk elements shift in tandem with the progressive exploration of the highstand to lowstand components (Figure 4). Highstand plays often require thorough understanding of the critical risk associated with trap, transgressive plays tend to require a stratigraphic component of sealing, while lowstand plays typically have significant reservoir risk. For example, the stepwise shift to lowstand, deepwater plays worldwide (George, 1996) has led to a focus on imaging of reservoir and fluid occurrence, continuity, and architecture (Imbert et al., 1996). This contrasts with earlier days when trap identification was the paramount focus of exploration (e.g., Halbouty et al., 1970). Summary and Conclusions
The creaming curve
method has proven to be a useful tool in exploration play prediction
worldwide, particularly in relatively simple, traditional plays. However,
complex patterns seen in some exploration histories suggest that more
sophisticated approaches are warranted. Viewing play development from a
Of course, caveats
should be offered in any case. Some plays do not develop the full range of
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John W. Snedden is currently Stratigraphy
skill area advisor with ExxonMobil Exploration Company in Houston, Texas.
He received his geology degrees from Trinity University (B.A.) Texas A&M
(M.S.), and Louisiana State University (Ph.D.). John has worked in U.S.
production and exploration, global exploration, exploration research, and
E&P technical service with Mobil and ExxonMobil over the last twenty-three
years. He has published and made presentations on ancient reservoirs of
Texas, the North Sea, Norway, Nigeria, Papua-New Guinea, Malaysia,
Indonesia, Germany, and Azerbaijan as J.F. 'Rick' Sarg
Rick Sarg is Stratigraphy Coordinator, ExxonMobil Exploration Company. He
received his Ph.D. in Geology, at the University of Wisconsin, Madison in
1976, his MS (1971) and BS (1969) in Geology at the University of
Pittsburgh, Pittsburgh, PA. His twenty-six years petroleum exploration and
production experience include assignments in research, supervision and
operations with Mobil (1976), Exxon (1976-90), Independent Consultant
(1990-92), Mobil Technology Company (1992-99), and now ExxonMobil
Exploration (2000-present). He was a member of the exploration research
group at Exxon that developed Don X. Ying Don Ying is a senior research
geologist in ExxonMobil Upstream Research Company. He joined Mobil
Exploration and Production Technology Company after receiving a Ph.D. in
geology from Stanford University in 1998. During his career with Mobil and
ExxonMobil, Don worked on a variety of research and research application
projects on deep-water reservoirs in offshore Nigeria, Angola and Gulf of
Mexico as His petroleum career started
with Research Institute of Petroleum Exploration and Development (RIPED)
of PetroChina after receiving a B.S. in geology from Beijing University in
1984. His assignments in RIPED and his graduate research included His current research interests are developing processes and workflows that enable geosciensts to build realistic geologic models during different business stages of petroleum exploration and production. |