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IPA05-G-032

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION Thirtieth Annual Convention & Exhibition, August 2005

SOURCE, GENERATION, MIGRATION AND CRITICAL CONTROLS ON OIL

VERSUS GAS IN THE DEEPWATER KUTEI PETROLEUM SYSTEM

Rui Lin* Art Saller*

John Dunham* Phil Teas*

Marek Kacewicz* Joe Curiale* John Decker*

ABSTRACT The deepwater portion of the Kutei Basin has been an exploration focus for Unocal Indonesia since 1996, which has led to several gas and oil discoveries. Numerous oil, gas and rock samples have been collected during exploration drilling, and analyzed for geochemistry to refine working model(s) of the operating deepwater petroleum system. The geochemical analyses indicate that allochthonous land-plant organic matter is the source of hydrocarbons in the deepwater Kutei Basin. The organic matter in turbidites is dominated by plant leaf fragments (occurring as thin coaly laminae), woody debris and less frequently resin bodies and recycled coaly particles. TOC contents can range from 1 to over 50% with hydrogen indices mostly between 100 and 400 (mg HC/g TOC). The overall kerogen assemblages are type III and subordinate type II, consistent with a gas condensate to a gas volatile oil petroleum system. No marine algal remains are evident in the deepwater sources, nor are any suggested by oil analyses. Oil/condensate chemistries vary widely but the fundamental genetic makeup of these deepwater liquids shares similar characteristics including (1) high pristane/phytane, oleanane/hopane and bicadinane/hopane ratios, (2) a C29-sterane dominance and the general lack of C30-steranes, (3) high lupanoids, (4) low sulfur and asphaltene, and (5) variable wax content. Gases are mainly thermogenic and the mixing of biogenic methane

* Unocal Corporation

and CO2 are observed in some shallow Pliocene reservoirs. The generation of oil and gas mostly occurred at oil window maturities. Migration fractionation and gas leakage, not source facies, exercised the dominant control on oil versus gas distribution in the Kutei deepwater. It is believed that single-phase hydrocarbon fluids were generated from the Middle- and Lower-Miocene strata, and migrated vertically through faults and fractured shales. Lower pressure-temperature in the upper Miocene and Pliocene reservoirs allowed phase segregation into gas and oil zones. Interbedded oil and gas resulted from multiple episodes of migration charging. Iterations of migration, fractionation and gas leakage enriched oils in an otherwise gas-rich basin. INTRODUCTION The Kutei Basin (which includes the Mahakam Delta) in East Kalimantan, Indonesia is a world-class petroleum province with over 70 TCF of gas and 5.4 billion barrels of oil and condensate in recoverable reserves (Figure 1). It is a gas-rich basin with large oil reserves (with an estimated basin-wide cumulative recoverable GOR of ca. 13000 scf/stb). Early discoveries of oil and gas fields are located near shore and on the shelf. Geochemical studies and petroleum system analyses of the oils and gases from these fields suggest that they were sourced from coals and carbonaceous shales of the delta complex (Combaz and de Matharell, 1978; Durand and Oudin, 1980; Curiale and Lin, 1991; Duval et al., 1992a, b). The kerogen assemblages were derived from land plants, belonging to types III and II. The pro-delta shales are

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considered to be of relatively poor quality and gas-prone. The high organic abundance in deltaic coals and shales, the significant depths of burial with thick deltaic sediments and the abundance of deltaic sands all provide an excellent habitat for gas and oil to accumulate in the Kutei Basin. Fluid migration study in the inboard and onshore areas of the Kutei Basin was undertaken by IFP and TOTAL (Combaz and De Matharell, 1978; Durand and Oudin, 1980; Radke et al., 1990). The authors concluded that the oils (in the Handil field) were sourced from a depth around 9200 feet corresponding to a Ro of roughly 0.7%; hydrocarbon fluids migrated vertically through faults into their deltaic sand reservoirs. This model is consistent with what was proposed later by Duval et al. (1992a,b), which still validly explains the sourcing and migration of petroleum in the shelf/onshore portion of the Kutei Basin. The pro-delta shales are observed to possess poor hydrocarbon generation potentials (Durand and Oudin, 1980; Curiale and Lin, 1991; and Duval et al., 1992a, b).

The observed inferior source quality of the pro-delta shales may have led people to consider that source potential would decline or even disappear extending into the deepwater Kutei Basin. Thus, for the deepwater Kutei Basin (water depths >2000 ft, Figure 1), early industry interpretations were concerned about significant exploration risks. These risks included the lack of (1) sufficient overburden (thermal maturity) for hydrocarbon generation, (2) organic richness (distal of pro-delta shale) and (3) the availability of well-developed sands in the deep water. It was thought that the deepwater acreage may not contain commercially viable petroleum systems (based on land-plant sources) unless alternative sources such as Eocene and Oligocene syn-rift lacustrine and/or marine carbonates/shales are present.

First analyses of deepwater source rocks, oils and gases in the Kutei Basin were reported by Lin (1998) and Lin et al. (2000) from drilling in the Merah Besar and Seno fields. The author(s) concluded that the hydrocarbon accumulations were sourced from land plant organic matter contained in turbidite facies. Peters et al. (2000) related the Kutei source rocks to sequence stratigraphy, and advocated a dominantly terrestrial source for the oil and gas accumulations in the Kutei Basin, including the deepwater. The authors grouped four oil families in accordance with sources

of different sequence stratigraphic units including high stand, low stand and transgressive settings. Curiale et al. (2005) further examined the internal architecture and variability of the land-plant super oil family in the deepwater Kutei Basin; the authors were able to recognize oil (sub)-families based on varying biomarker (molecular) signatures. Continued drilling and analyses further testified that substantial source rocks for hydrocarbons do exist in the deepwater Kutei Basin. Large quantities of gas (ca. 10 TCF) and oil (ca. 200-300 mmbo) have been discovered to date (Redhead et al., 2000; Dunham and McKee, 2001), reservoired in Pliocene and Miocene sands deposited in deepwater environments.

This paper aims to (1) establish a deepwater petroleum system model in which the source rocks are based on the allochthonous remains of land plants involving significant leaf fragments, (2) identify and characterize these land plant based deepwater organic facies in association with turbidites, (3) illustrate an overall gas condensate to gas volatile oil system at generation, (4) demonstrate how episodic migration, fractionation and gas leakage lead to variable gas liquid ratios and oil versus gas fields, and (5) confirm volumetric sufficiency of these deepwater organic facies for commercial gas and oil accumulations. BRIEF GEOLOGIC OVERVIEW The Kutei Basin is a large Tertiary depocenter, situated in eastern Kalimantan and extending into the Makassar Strait; it contains the Mahakam Delta (Figure 1). Rift basin formation probably initiated between Paleocene and early Eocene times (van de Weerd and Armin, 1992; Moss et al., 2000; Nichols et al., 1998). The rifting led to the formation of the Makassar Strait, possibly with oceanic crust to the north and continental thinning in the south (Nichols et al., 1998). As a result, Eocene syn-rift half grabens were formed (Guritno et al., 2003), which were subsequently filled with alluvial, fluvial and lacustrine sediments. The Kutei Basin entered a sag phase in the Oligocene during which time marine carbonate was deposited along the basin margins (Saller et al., 1993). Eastward progradation of the ancient Mahakam delta commenced in Late Oligocene (Saller et al., 1993), and deltaic sedimentation continues today. As a consequence of continued basin subsidence and creation of accommodation space for deltaic sedimentation by the ancient Mahakam River, a very thick column of

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deltaic sediments (>10 kilometers thick in places) was deposited from the Miocene to the present. The Miocene and Pliocene deltaic sandstones form the main reservoirs for the gas and oil accumulations in the Kutei Basin. By mid-Miocene, the extensional tectonic regime shifted to east-west compression, initiating formation of fold belts which are key to many gas and oil accumulations in the Kutei Basin. In the northern deepwater Kutei Basin, a gravity driven extension-toe-thrust coupled with accommodation antithetic faults developed in the mid-Miocene and continues today. In the central and southern deepwater Kutei Basin, much less faulting occurred (Guritno et al., 2003), where accumulations are notably gas prone. Source rock developments in the basin depended on the tectono-stratigraphic framework. The overwhelming majority of hydrocarbon accumulations in the basins are correlated to the Miocene deltaics (Durand and Oudin, 1980; Duval et al., 1992a, b; Curiale and Lin, 1991; Peters et al., 2000). Two main episodes of coal and carbonaceous shale depositions are observed in association with the development of the ancient Mahakam Delta. One episode occurred in the mid-Miocene, and the other commenced in the upper Miocene (ca. 8 mybp) which continues today. Very limited oil and gas condensate accumulations suspected of Eocene syn-rift and Oligocene marine carbonate origins are also known in basin margins. METHODS AND INSTRUMENTATION Screening geochemical analyses were performed by Core Laboratories (Jakarta) and Lemigas (Jakarta). Deepwater wells were drilled with either an oil (Mentor)-based mud (OBM) or synthetic (Saraline)-based mud (SBM). Therefore, a rigorous procedure involving solvent extractions was employed to remove SBM/OBM from the samples prior to source rock analyses. Petrographic analyses were performed using a Zeiss light microscope equipped with both white- and blue-light illuminations. Whole oils/condensates from both DST and MDT tests were analyzed for high resolution gas chromatography (GC), GC-MSD and GC-MSMS, which were carried out by Baseline/DGSI (Houston, Texas, USA). Instrumentation and analytical conditions for these analyses were reported previously (Curiale et al., 2005). GC-IR-MS analyses were undertaken at the

University of Oklahoma (Norman, Oklahoma, USA). The stable carbon isotopes were determined for C1, C2, C3, iC4, nC4 and CO2. Deuterium isotope was measured on methane. Gas isotopic analyses were performed by Zymax (San Luis Obispo, California, USA). RESULTS AND DISCUSSION Oil, Gas and Condensate Properties The fluid types and properties in the deepwater Kutei Basin vary widely, ranging from dry gas yielding little condensate, to wet gas yielding >70 stb/mmscf, and from light volatile oil to waxy low GOR black oils. The oil fields are located in the northern deepwater Kutei Basin (Seno, Merah Besar and Ranggas) (Figure 1), associated with intense faulting. Complex and interbedded oil and gas zones are common in these fields. Gas fields were discovered in the central and southern outboard of the delta (Gehem, Gula and Gendalo) (Figure 1). The gas fields exhibit overall depth-dependant trends of gas composition and condensate yield; increasingly heavier gases (more C2+ components relative to C1) and higher condensate yields are found in deeper reservoirs. Nonetheless, localized reversal of these trends do exist. Limited waxy and low GOR oils are found in the deep mid-Miocene reservoirs below the gases. The gases are mostly sweet with low non-hydrocarbon contaminants. Nitrogen (N2) content is mostly below 0.5% and CO2 content below 9%. H2S content is mostly below detection limit (

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removed but whose aromatic and cyclic saturate hydrocarbons are enriched to yield comparatively low API gravity. A third population represents the condensates. Due to the generally high SBM/OBM contamination, most condensate samples were not determined for bulk properties, thus having a small sample population in Figure 2b. Wax content in the oils varies widely from little to 18% (Figure 2c). The high wax (>10%) oils are associated with high pour points (Figure 2d) which is a significant concern for production flow assurance. Since the oils are depleted in asphaltene and NSOs, wax content is the controlling factor on viscosity and pour point. The medium wax oils (4-10%) are more often associated with high GORs. These levels of wax would have otherwise been manageable in a shelf production environment; nonetheless, it still is a significant production flow assurance concern in a deepwater operating environment (Gallup et al., 2005). Figure 2d plots pour point against tvdbml (true vertical depth below mudline). Given significant data scattering, an overall trend of increasing pour point with depth is suggested, largely due to migration fractionation (to be elaborated below). In consideration of a seafloor temperature of ca. 40oF, a large proportion of the oil and condensate (those with high and medium level wax, 4 to over 20%) samples poses flow assurance concerns. The low wax population (0-4%) is due to evaporative migration of the lighter hydrocarbons, or biodegradation during which waxy long chain n-paraffins were consumed. The Kutei deepwater oils and condensates are also enriched in long chain fatty acids, presumably due to their land plant precursors and relative low maturities. Similar to wax, these fatty acids were derived from plant leaf fatty acids. These fatty acids can react with bicarbonate in production water, causing emulsion by mechanism similar to soap formation (Gallup et al., 2005). Oil, Gas and Condensate Geochemistry Despite rapid variation in fluid types and properties in the deepwater Kutei Basin, the underlying genetic characteristics of the oils and condensates are remarkably similar. Molecular (biomarker) ratios vary widely even within a well but they all fall in the domain of a common land-plant origin. Figure 3 displays the gas chromatograms of select oil and condensate samples. The n-paraffin envelopes of the

samples differ with each other, varying from light condensate (Figure 3a), waxy condensate (Figure 3b), light oil (Figure 3c), to waxy black oil (Figure 3d). The oils and condensates also have variable fluid properties. Nevertheless, they are characterized by similar genetic molecular ratios such as high pristane/phytane ratios (IP-19/IP-20), other high isoprenoids (IP-13, -14, -15 and -16) and relatively high toluene and xylenes, all relating to their land-plant precursors. Not only are these genetic molecular characteristics similar to other deepwater oils and condensates, but also do they resemble those from the onshore and shelf fields. The distributions of pristane/phytane ratios comparing onshore, shelf and deepwater fields show that the overwhelming majority fall in a similar range (mostly between 4-8, reflecting an initially oxic depositional environment). Whole oil isotope analyses of DST and production samples free of SBM/OBM also confirm genetic similarity (of land plant origin) for the deepwater and shelf oil/gas accumulations. Oil and condensate samples from the shelf and deepwater both have stable carbon isotope ratios falling in a very narrow range from -27 to -29 (o/oo). Compound-specific carbon isotope analyses by GC-IR-MS yield consistent interpretations that, regardless of oil versus condensate or shelf versus deepwater, the isotope signatures are very similar (results not shown), reflecting common land plant organic sources. The low sulfur and asphaltene contents are also characteristic of non-marine land plant origin, regardless of whether the source facies are bedded coal on the shelf or coaly laminae in the deepwater turbidites. Biomarker distributions obtained from GC-MSD and GC-MSMS also point to a common land plant origin for the deepwater Kutei Basin oils and gas condensates. They are characterized by high levels of oleananes (OL) and bicadinanes (W and T) (Figure 4); both are molecular markers indicative of angiosperms (Peters and Moldowan, 1993). More specifically, bicadinanes are thought to have been derived from resins of the angiosperm family, Dipterocapaceae (van Aarssen et al., 1990). Over 120 species of Dipterocarpaceae are still extant in Indonesia, including Kalimantan. They occupy the inland fluvial valley and, more importantly, form high canopies on hills and mountains. Dipterocarp trees are prolific resin producers, which are resistant to biodegradation and, once solidified, they could have been transported

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through the ancient Mahakam River into the Makassar Strait. Other resins may be preserved in leaves and woody fragments (e.g. those in resin duct), which were eventually deposited on the Kutei shelf and in deepwater. Land plant organic matter derived from the hinterland would have been mixed with those from the coastal environments which were dominated by mangrove, nypa, other palms and back-swamp trees (Bob Morley, personal communications). The remains of these plant organic assemblages led to the formation of non-marine type III and II kerogens (despite the fact that they were eventually deposited in the deep marine environment). Another suite of molecular markers indicative of land plant precursors is the lupanoids (Curiale et al., 2005). Relative sterane distributions by GC-MSD and GC-MSMS show a C29-sterane dominance over the C27- and C28-steranes, which is also characteristic of petroleum derived from land plant sources (Figure 5). In the GC-MSMS analyses, n-propyl-C30-steranes, which are indicative of certain types of marine algae, are absent suggesting no observable marine contribution. It is reasonable to assume that marine phytoplankton including algae should have been present in the photic zone of the ancient Makassar Strait. The lack of algal remains reaching and becoming preserved in the deepwater sediments may suggest conditions unfavorable for their precipitation and preservation. The strong current in the Makassar Strait and the generally oxic nature of the water body probably diminished their chance of preservation in the sediment column. Gas molecular and isotopic analyses are effective tools in determining gas origins (e.g. biogenic versus thermogenic) and deriving maturity at generation and possible mixing from multiple sources. A overwhelming majority of the gases in the deepwater Kutei Basin have methane 13C values of -35 to -52 (o/oo), which, with high gas wetness, are characteristic of a thermogenic origin (likely of oil window maturity) (Whiticar, 1994). Presumably they were sourced from the type III kerogens, as supported by the biological markers in the gas-associated condensates. A subordinate number of gases exhibit characteristics of biogenic-thermogenic mixing with methane 13C values in the range of -55 to -65 (o/oo); these gases are mostly reservoired in the shallow Pliocene sands, typically with low condensate yields. The thermogenic gases are dominantly reservoired in upper Miocene turbidite sands. Two gases, made up

of almost pure methane, from the Pliocene reservoirs have 13C values of ca. -75 (o/oo), likely resulting from biogenic origin. Source Rock Organic Richness One of the most striking source rock characteristics of the deepwater Kutei Basin is the abundance of land plant organic materials easily observable in conventional cores. Frequent occurrences of parallel coaly laminae, chaotic coaly laminae and fine land plant debris in sands and shales are easily revealed in the cores. The organic-rich laminae tend to be concentrated in the sand-prone facies of turbidites. In general, the TOC contents obtained from cutting analyses of the deepwater Kutei wells are between 1 and 2%, with a few exceptions. This relative lack of organic variability, which is in contrast to rapidly varying organics observed on conventional core samples, is largely due to the 60-ft compositing of cutting samples; organic facies variations occur in millimeter to centimeter scales in the deepwater Kutei Basin. Core analyses at a tighter spacing (1-ft) reveal rapid vertical variability in organic abundance. The TOC contents obtained from core analyses range from less than 1% to over 50%. An example is shown in Figure 6 from the Ranggas-4 well; the cores from this well have an average TOC of 3.03%. This level of organic richness is impressively high as they represent the average TOC contents of the total strata cored, not from the analyses of selected source intervals. The high levels of TOC abundance confirm that the organic richness based on land plant organic materials are sufficient in supporting commercial accumulations in the deepwater. This can be illustrated by MSSV-pyrolysis and by volumetric modeling (results not shown due to limited space). The high-TOC (>4%) core samples are often related to the parallel coaly laminae facies (to be discussed below), which are intimately associated the sand-prone facies in turbidites. The lack of bedded coals in the deepwater is in striking contrast to those on the shelf and onshore, where bedded coals are abundant. The absence of bedded coal in the deepwater must have been related to the re-distribution of the sediments (including peat and lignite) during turbidity flows, whose turbulent currents mixed sand, mud and peat (and lignite) into thinly-bedded lithologies of sands, coaly laminae and laminated shale. In hemipelagic mudstones, the land-plant organic matter are finely disseminated and often

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oxidized, possibly representing suspension particles of land-plant or coaly debris deposited during high stand. Deepwater Organic Facies There is rapid variation in organic facies in the Kutei Basin deepwater turbidites, as is evident in the conventional cores. To date, at least three organic facies have been recognized, including (1) the parallel coaly laminae facies, (2) the chaotic coaly laminae facies, and (3) the laminated shale facies. Parallel coaly laminae facies: Figure 7 displays the photographs of two polished core plugs taken from the Gendalo-3 well (upper right and lower right photos); they reveal parallel coaly laminae interbedded with very thin layers of turbidite sand. Per the origin of these organic laminae, morphologically, the most plausible explanation would be that they are remains of leaf fragments, since there are no other plant parts that would easily explain the abundance of the flaky laminae. Tracing of the thin coaly laminae on the polished core plugs indicate that their sizes are mostly in the 0.5 to 1 centimeter range, sizes comparable to peatified leaf fragments observed on the modern Mahakam Delta (left photo, Figure 7). It is conceivable that these peatified leaf fragments could have been transported into the deepwater Makassar Strait by turbidity currents, leading to the flaky coaly laminae (Figure 7). Geochemically, the parallel coaly laminae facies are organic rich (6.44 and 7.01% TOC, respectively for the plugs shown in Figure 7), and relatively hydrogen rich (with hydrogen indices of 241 and 300 mg HC/g TOC). These kerogens are type III/II, which are capable of generating gas and volatile oil. Light microscopy of an oriented core block (11646.92 ft-md) reveals that the coaly laminae are made up of thin vitrinite (V) bands intimately associated with cutinite (C) and resinite (R) (Figure 8); the upper-right microphotograph shows two cutinites (yellow fluorescing) closely interbedded with thin bands of vitrinite (non-fluorescing). These thin bands of cutinite and vitrinite likely had formed from a leaf fragment. The cutinite was likely derived from the leafy cuticles associated the upper and lower epidermis whereas the vitrinite bands may have formed from gelified lignin/cellulose of the veins and the parenchyma cells inside the leaf. The leafy cutinite macerals are suspected also to be responsible

for the wax and fatty acids, two primary production flow assurance issues, in the oils and condensates of the deepwater Kutei Basin (Gallup et al., 2005). The lower-right microphotograph in Figure 8 shows another coaly laminae made up of a train of strongly yellow-fluorescing resinite (R) (elliptical resin beads) bound within a thin band of vitrinite (V). In this laminae, there is however no convincing evidence that it is a leaf fragment, as they are not bound by cutinite covering the upper and lower epidermis. The relatively lower densities of the resinite and cutinite macerals in the coaly laminae may have been instrumental in their relative enrichment in the tail-end of the turbidite. Resinite, in addition to cutinite, is one of the most important liptinite macerals in the deepwater, which by themselves are oil prone. Surprisingly, few sporinite (spore and pollen) particles and no alginite are observed in the deepwater cores. It is significant also to make reference to the resinous materials and the molecular characteristics of the oils and gas-associated liquids in the deepwater. Two forms of resinite are frequently observed including the typical yellow fluorescing beads (resinite) (lower right, Figure 8), and the intensely greenish-fluorescing fluorinite (upper right, Figure 8). Other resinous materials may be dispersed within the vitrinite and mineral matrix. Some of these resinous materials may be related to the bicadinanes from the Dipterocarpaceae family (van Aarssen et al., 1990). Also illustrated in Figure 8 (left) is a modified van Krevelen diagram plotting the hydrogen versus oxygen indices of core samples from the Gendalo-3 well. The diagram suggests that a substantial proportion of the coaly laminae facies is comprised of type II kerogens which are volatile-oil prone. The facies can have hydrogen index values ranging from less than 100 to over 400 (mg HC/g TOC). The higher HI samples likely contain higher concentrations of liptinite macerals. The parallel coaly laminae facies are likely the most important organic facies in contributing to the gas and oil hydrocarbon accumulations in the deepwater Kutei Basin. Chaotic coaly laminae facies: This facies contains individual coaly laminae in more or less random orientations. These individual coaly laminae are embedded in a sand matrix and, microscopically, fine

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sand grains are often seen to have deformed or even broken the flaky vitrinite laminae. This facies is very interesting yet the most puzzling of all. In bulk chemistry from Rock-Eval pyrolysis, the source-rock parameters do not resemble the parallel coaly laminae facies discussed above. It has low TOC contents (0.5-2.0%) and low hydrogen indices (80 to 180 mg HC/g TOC) (Figure 8). These properties are gas-condensate prone. Morphologically the chaotic coaly laminae resemble leaf fragments; however, there is little leaf chemistry in these laminae. The origin of these chaotically-oriented vitrinite laminae is unclear. Laminated shale facies: The TOC content of this facies varies from 0.4 to 2% but mostly between 1-2% . This facies can be intimately interbedded with the parallel coaly laminae facies and very thin layers of sand. Hand-picked samples have shown that the TOC content can be over 2%. The hydrogen indices are typically near 100 (mg HC/g TOC), which may vary from 80 to 180 (mg HC/g TOC) (Figure 8). Bulk chemical kerogen typing of this facies suggests type III organic assemblages. Under the light microscope, the terrigenous (laminated) shale facies are enriched in clays, silts with vitrinite wisps. Unlike the parallel coaly laminae facies, the vitrinite bands in this facies are thin and short, and are more properly characterized as microscopic wisps. Liptinite macerals such as cutinite and resinite may appear sporadically, but relatively rare. This facies is largely gas-condensate prone, though the chemistry of the condensate may be oil like. In more distal shale facies, the organics are comprised of very fine vitrinite particles and occasionally associated with recycled vitrinite. Hydrocarbon Generation Sufficient overburden for thermal maturation is a critical risk in deepwater exploration. To evaluate the source rock maturity of the deepwater Kutei Basin, cutting samples from numerous deepwater Kutei Basin wells were determined for vitrinite reflectance (Ro). Results overall suggests that a Ro value of 0.60% (top oil window) is reached at nearby 9,500 (1500) tvdbml. Given the water depths (2000 to over 5500 ft) of the wells, top oil window is often not reached by drilling. Measured Ro is observed to increase from 0.20 to 0.55-0.60% for most wells. Furthermore, Ro values of the deepwater Kutei Basin are thought to have been suppressed (Joe Curiale, personal communications based on VIRF and FAMM

analyses). Thus, Ro corrections must be applied in maturity assessment and thermal/generation modeling. DST temperatures, geothermal history and kerogen kinetics are necessary considerations to understand hydrocarbon generation and maturity. Figure 9 displays the measured Ro, the modeled Ro and the burial/generation histories of a deepwater Kutei Basin well (Gendalo-2). A slightly revised top oil window (0.55% Ro instead of 0.60% Ro) is chosen to reflect the low activation energies of the resinous materials. The rate of thermal decomposition from kerogens into oil and gas depends on the chemical structure and composition of a kerogen assemblage. This rate of reaction governs the quantity of hydrocarbons generated at different levels of thermal maturity. Kerogens from the deepwater cores were determined for kinetic properties. The activation energies populate over a broad range from 42 to 66 kcal/mole with a mode at 52 kcal/mole, a distribution characteristic of type III kerogen. Small differences are however observed between the deepwater Kutei Basin kerogens and those typical of humic coals (type III). The low activation energies between 42-46 kcal/mol in the deepwater Kutei kerogens likely reflect the presence of resinous materials, which are observed by kerogen microscopy and by indication from the resin biomarkers. These newly acquired kerogen kinetics from the deepwater Kutei Basin were applied to 1-D thermal and generation modeling. The results show that, for both gas and oil, the onset of hydrocarbon generation occurs near the top mid-Miocene (KR-80 or X4) (Figure 9). Significant hydrocarbon generation also occurs within the mid-Miocene strata. These strata correspond to the early pulse of intense coal deposition on the ancient Mahakam Delta, which likely would also have led to the abundance of coaly laminae in the deepwater Kutei Basin. The kerogen kinetics were also employed to model cumulative gas and liquid (condensate) hydrocarbon generation for the mid-Miocene source strata. Generation modeling estimates that the source rocks in the mid-Miocene generated, on average, about 116 mg of gas and 36 mg of liquid per gram of TOC. This would translate to cumulative GOR at generation of about 22,000 (scf/stb) or a CGR (condensate gas ratio) of 45 bbl/mmscf, indicating an overall gas condensate system. It is absolutely critical to recognize that the oil versus gas composition of a field is not only

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dependent on the source facies (primary process) at generation, but also on post-expulsion secondary/ tertiary processes such as migration fractionation, tertiary re-migration, gas leakage and differential migration rates. Migration, Fractionation and Gas Leakage PVT experiments of constant volume depletion (CVD) illustrate that, in order for a source system of dominantly gas condensate prone kerogen to have formed an oil field, many iterations of phase segregation, fractionation and gas leakage had to occur. The Kutei Basin is a gas-rich basin with large oil reserves. Cumulative recoverable reserves for the entire basin, if hypothetically placed in a single container, would lead to a GOR of ca. 13,000 scf/stb. This would be a gas condensate fluid. However, empirical observation in the Kutei Basin suggests that the relative distribution of oil versus gas is not uniform, ranging from gas to oil fields. Structural observation reveals that the intensely faulted fields are often enriched in oils, whereas those poorly faulted are dominantly gas. This empirical observation remains valid into the deepwater Kutei Basin that the oil fields including Seno, Merah Besar and Ranggas are intensely faulted, whereas the gas fields including Gehem, Gendalo and Gula are very poorly faulted. Idealized migration fractionation of fluid would lead to well-defined depth trends in gas composition, condensate yield and fluid type driven by buoyancy and differential migration rates. Higher condensate yields are tested in the deeper gas pays, and low-GOR waxy oils are discovered underlying the gases (e.g. Gehem and Gula fields). Intuitively, these waxy oils may represent the residual pools, while the associated gas and condensate migrated further up the section. Such simple depth trends, however, are more often (than not) disturbed and distorted by crossing migration pathways, migration timing and multiple episodes of mixing. This can result in complicated occurrences of fluid types (i.e. interbedded oil and gas) and gas compositions (alternate wet/dry gases). In highly faulted areas such as Ranggas and Seno, interbedded oil and gas pays are encountered, and there is not an obvious C2+/C1 trend with depth. It is easy to comprehend that, over millions of years during which oil/gas generation and migration occurred, detailed routing of fluid movements and

their pathways to different source pods as well as re-migration of fluids would bring about complex interbedding of oil and gas pays. These same processes could also have distorted or even reversed gas compositional trends with depth. PETROLEUM SYSTEM SYNOPSIS AND CONCLUSIONS A petroleum system model is proposed for the sourcing, migration, fractionation and distribution of oils and gases in the deepwater Kutei Basin. The source rocks are comprised largely of type III kerogens with subordinate type II, a quality consistent with being gas condensate to volatile oil prone. Deepwater organic facies (most importantly the parallel coaly laminae) vary in millimeter to centimeter scales, but statistically the cumulative source facies of all the strata maturing into the hydrocarbon generation windows overall have high gas liquid ratios (GLR) (e.g. 15000-25000 scf/stb based on generation modeling and pyrolysis experiments). In the Middle (and Lower) Miocene source kitchens where pressure and temperature are significantly higher than the dew points of the high GLR fluids, single-phase expulsion and migration occurred (Figure 10). Fluid movement took place along faults, shale fractures and local sand bodies. As these fluids migrated and charged upper Miocene turbidite reservoirs, where pressure and temperature declined to below fluid dew point, a thin oil leg was formed (Figure 10). Tertiary migration of the vapor (gas) phase into shallow Upper Miocene and Pliocene reservoirs formed gas condensate pays. As gas leakage happened episodically or gradually over geologic time, pressure declined and retrograde condensation of liquid occurred in the reservoirs. Pressure accommodation during gas leakage and tertiary re-migration, in geologic time, allowed more fluids to move from the source kitchens into the deeper and then shallower reservoirs, a process automatically replenishing itself through multiple iterations. In highly faulted fields, this process of tertiary re-migration, gas leakage and replenishing charge allowed oil enrichment both in deep and shallow reservoirs (e.g. Seno and Ranggas). In contrast, in poorly faulted fields such as the Gehem, Gendalo and Gula fields, the process of pressure accommodation (by gas leakage and tertiary migration) was limited. Pressure accommodation for more fluids to move up the section was thus

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constrained, leading to predominantly gas pays with well-defined compositional and fluid-type trends with depth. Residual oils may be found below the gas, though of low mobility (high viscosity and low permeability) which limits the economic value of these deep oils, particularly in a deepwater operating environment. Prohibiting complex migration mixing and charging, the well-defined compositional trends of C2+/C1 and gas to oil may be explained by vapor-liquid partitioning (phase equilibrium) in the reservoirs (while in residence) and differential migration rates during fluid movement according to Darcys law (q/A = -k/*(dP/dX) where q is flow rate, A flow area, k permeability, viscosity, P pressure, X distance). During migration (in transit from source kitchen to reservoir and from reservoir to reservoir), the relative rate of migration for each molecule is proportionally dependent on permeability and inversely proportional to viscosity (prohibiting inter-molecular interactions). In fields which have few faults, and the fault movements had been largely non-dilated, the high viscosity of C2+ relative to C1 allowed the former to migrate at slower pace, leading to gas pays of increasing wetness and condensate yield with depth. In fluid movement along dilated fault movements, particularly in structurally complex areas such as Seno and Ranggas, effective permeability for each molecule became very large; thus the flow rates were exceptionally high for all the molecules, and the impact of the differences in viscosities was minimized. This led to poorly segregated fluid types by depths and across the fields. In these dilated flows, fractionated residual oils (even waxy oils), with pressure replenishment, could reach shallower Upper Miocene and even Pliocene reservoirs. A petroleum system event chart for the Kutei Basin is shown in Figure 11. It is believed that mature source rocks occur mostly in the Middle and possibly Lower Miocene. Single phase gas-rich fluids with solution liquids were generated within the kitchen at high pressure and temperature; the fluids migrated and charged into upper Miocene and Pliocene reservoirs (Figure 11). Entrapment of hydrocarbon fluids happened in structural four-way closures as well as three-way closures bound by faults. Tertiary migration of gas caps fluids and gas leakage (Figure 11) led to the enrichment of oil fields in structurally complex areas where faults allowed migration fractionation and gas leakage to have occurred. In

poorly faulted areas, gas leakage and resulting oil enrichment were very limited, leading to mostly gas condensate fields inherent of the type III source kerogens. ACKNOWLEDGEMENT The authors would like to thank Unocal Indonesia and its partner Eni for approval to publish this study. They would like to acknowledge the deepwater exploration team in Unocal Indonesia for sample collections, and the exploration management team, Gary Christensen, Jim Friberg, Joel Alnes, Tim Nicholson and Sherman Smith for their enduring budget support in undertaking the study. The authors also wish to thank Dr. Ron Noble for his review and improvement of the text. Specifically, one of us (Rui Lin) would like to thank his assistant, Ms. Chalermporn M., for her assistance in data compilation, plotting and the preparation of some illustrations in this paper. CoreLab Jakarta, Lemigas, Baseline/DGSI, and Zymax are acknowledged for their analytical services. REFERENCES Combaz, A. and De Matharell, M., 1978. Organic sedimentation and genesis of petroleum in Mahakam delta, Borneo. AAPG Bull., vol. 62, pp. 1684-1695. Curiale, J. A. and Lin, R., 1991. Tertiary deltaic and lacustrine organic facies: comparison of biomarker and kerogen distributions. Org. Geochem., vol. 17, pp. 785-803. Curiale, J. A., Lin, R. and Decker, J., 2005. Isotopic and molecular characteristics of Miocene-reservoired oils of the Kutei Basin, Indonesia. Org. Geochem., vol. 36, pp. 405-424. Dunham, J. B. and McKee, L.D., 2001. Emergence of the Ganal gas trend deep water Kutei basin, Indonesia; 2001 AAPG/SEPM Annual Meeting, Program with Abstracts, p. A54. Durand, B. and Oudin, J.L., 1980. Exemple de migration des hydrocarbures dansune serie deltaique: le depta de la mahakam, Kalimantan, indonesie. Proceedings Tenth World Petroleum Congress 2, p. 3-11.

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Duval, B. C., Choppin de Janvry G., and Loiret, B., 1992a. Detailed geoscience reinterpretation of Indonesia's Mahakam delta scores. Oil & Gas J., Aug. 10, 1992, p. 67-71. Duval, B. C., Choppin de Janvry G., and Loiret, B., 1992b. The Mahakam delta province: an ever-changing picture and a bright future, paper presented at the 24th OTC (Houston), OTC 6855, p. 393-404. Gallup, D.L., Smith, P.C., Star J.F. and Hamilton, S., 2005. West Seno deepwater development case history production chemistry: 2005 SPE International Symposium on Oilfield Chemistry, SPE 92969, Society of Petroleum Engineers, p. 1-13. Guritno, E., Salvadori, L., Syaiful, M., Busono, I., Mortimer, A., Hakim, F.B., Dunham, J., Decker, J. and Algar, Sam, 2003. Deep-water Kutei Basin: a new petroleum province: Proceedings, Indonesia Petroleum Association, Twenty-ninth Annual Convention and Exhibition, October, 2003. Lin, R., 1998. Deepwater petroleum system at Merah Besar and vicinities: oils, gases and source facies. unpublished Unocal internal report. Lin, R., Schwing, H.F. and Decker, J., 2000. Source and migration in the Makassar-Mahakam deep water petroleum system, East Kalimantan, Indonesia. Bulletin of the American Association of Petroleum Geologists 84, p. 1455 (abstract). Moss, S.J., Clark, W. and Baillie, P., 2000. Abstract: Tectono-Stratigraphy Evolution of the North Makassar Basin, Indonesia. Abstracts 2000 AAPG International Conference and Exhibition. p. A163. Nichols G.J., Cloke, I.R. and Hall, R., 1998. Eocene extensional basin formation, eastern Borneo. Abstract, Proceedings, Indonesian Petroleum Association, Twenty-Sixth Annual Convention, p. 350.

Peters, K.E. and Moldowan, J.M., 1993. The biomarker guide, Prentice Hall, New Jersey, p. 363. Peters, K.E., Snedden, J.N., Sulaeman, A., Sarg, J.F. and Enrico, R.J., 2000. A new geochemical-sequence stratigraphic model for the Mahakam delta and Makassar slope, Kalimantan, Indonesia: AAPG Bulletin, v. 48, p. 12-44. Radke, M., Garrigues, P. and Willsch, H., 1990. Methylated dicyclic and tricyclic aromatic hydrocarbons in crude oils from the Handil field, Indonesia, Org. Geochem., v. 15, p. 17-34. Redhead, R. B., Lumadyo, E., Saller, A., Noah, J.T., Brown, T.J., Yusak, Yusri, Inaray, J., Ma, T., May, R. and Lin, R., 2000. West Seno Field discovery, Makassar Straits, East Kalimantan, Indonesia, in GCSSEPM Foundation 20th Annual Research Conference, Deep-water Reservoirs of the World, p. 862-876. Saller, A. H., Armin, R.A., Ichram, L.O. and Glenn-Sullivan, C., 1993. Sequence stratigraphy of aggrading and backstepping carbonate shelves, Oligocene, Central Kalimantan, Indonesia, in R. G. Loucks and J. F. Sarg, eds., Carbonate Sequence Stratigraphy: Recent Developments and Applications: AAPG Memoir 57, p. 267-290. Whiticar, M. J., 1994. Correlation of natural gases with their sources. in The Petroleum System - from Source to Trap AAPG Memoir 60., p. 261-283. van Aarssen, B.G.K., Cox, H.C., Hoogendoorn, P., de Leeuw, J.W., 1990. A cadinene biopolymer present in fossil and extant dammar resins as a source for the cadinanes and bicadinanes in crude oils from South East Asia. Geochimica et Cosmochimica Acta, v. 54, p. 3021-3031. van de Weerd, A., and Armin, R.A., 1992. Origin and evolution of the hydrocarbon basins in Kalimantan (Borneo), Indonesia: AAPG Bulletin, v. 76, p. 1778-1803.

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Figure 1 - Kutei Basin Field Location Maps.

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Figure 2 - Deepwater Kutei Basin Gas and Oil Properties.

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Figure 3 - High Resolution Gas Chromatograms of Select Oils and Condensates from the Deepwater Kutei Basin.

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Figure 4 - GC-MSD Comparing the Biomarkers of a Gehem-2 Condensate (DST-1: 15460 ft) and an Underlying Oil (MDT: 16022 ft) Suggesting

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Figure 5 - Regular Sterane Distribution Suggesting Land Plant Source for the Deepwater Kutei Oils and

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Figure 7 - Size and morphologic comparison between peatified leaf fragments and the parallel coaly laminae facies in deepwater cores.

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Figure 8 - Optical and Chemical Kerogen Typing of the Deepwater Organic Facies.

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RV

C

Q

464

Figure 9 - 1-D (Thermal) Modeling of a Deepwater Kutei Basin Well.

Gendalo-2 Well Deep 45.4 mW/m2

Maturity (%Ro)0.1 1 10

D

e

p

t

h

S

u

b

s

e

a

(

f

e

e

t

)

0

10000

20000

30000

PleistoceneZ6fsZ5fs (TPliocene)Z4fsZ4sbZ3ts (TMiocene)X0tsX1fsX1sbX2fsX2sbX4sb (mid-Miocene)

X5ts

X8sb

X10sb

X13 (lower-Miocene)

Fm

t = 0

Maturity

mat regress

Early Generation0.55 to 0.8 (%Ro)

Peak Generation0.8 to 1.1 (%Ro)

Late Generation1.1 to 1.3 (%Ro)

Wet Gas Condensate1.3 to 2 (%Ro)

Dry Gas2 to 2.5 (%Ro)

%Ro

Gendalo-2 Well Deep 45.4 mW/m2

90(F)120(F)

150(F)

180(F)

210(F)240(F)270(F)

300(F)330(F)360(F)390(F)

420(F)450(F)

Age (my)05101520

D

e

p

t

h

S

u

b

s

u

r

f

a

c

e

(

f

e

e

t

)

0

10000

20000

30000

HPlePliMio

PleistoceneZ6fsZ5fs (TPliocene)Z4fsZ4sbZ3ts (TMiocene)X0tsX1fsX1sbX2fsX2sbX4sb (mid-Miocene)

X5ts

X8sb

X10sb

X13 (lower-Miocene)

Fm

t = 0

Early Generation0.55 to 0.8 (%Ro)

Peak Generation0.8 to 1.1 (%Ro)

Late Generation1.1 to 1.3 (%Ro)

Wet Gas Condensate1.3 to 2 (%Ro)

Dry Gas2 to 2.5 (%Ro)

465

Figure 10 - Generation-Migration Model Illustrating Oil/Gas Fractionation and Oil Enrichment via Gas Leakage.

Middle-Lower Miocene Mature Sources:

Fm P-T>>Dew Point P-T Single Phase Fluid

Gas Leakage and Mud Volcanoes

Fractured Shale

Fault

Upper Miocene Reservoirs: Fm P-T

466

Figure 11 - Petroleum System Event Chart for the Kutei Basin.

PLEISTOC

ENE

TO R

ECEN

T

PLIOC

ENE

SOURCE

EOCENE OLIGOCENE MIOCENE

LOWER UPPER MIDDLE LOWER UPPER

GEOLOGIC TIME

SCALE

PETROLEUM SYSTEM EVENTS

RESERVOIR

SEAL

TRAP

GENERATION AND MIGRATION

PRESERVATION

CRITICAL MOMENT

FORMATION

KR20KR160-X13KR240-X15 KR100-X6 KR50-Z3

MY

BP 0

10 5 15 20 25 30 40 35

Basin Margins Ultra-Deepwater?

Syn-Rift Coal/Shale

Majority of Kutei (and DW) Oil and Gas Accumulations

Marine Carbonate Deltaic Coal/Shale

Deepwater Turbidite Coaly OM

Onshore Kutei Deltaic Sand Deepwater Turbidite Sand

Deltaic Intraformation Shale Deepwater Shale/Mudstone

Four Way Three Way - Fault

Shelf: 16+ to 0 mybp DW: 13-0 mybp, 6-0 mybp critical

Gas Leakage Biodegradation

X16

Migration: Deep: Single-Phase Fluid via Sand,

Shale Fracture and Fault Formation P-T>>Dew Point P-T Shallow: Multiple-Phase Fluids

Migration Fractionation, Gas Leakage