Source Rock Geochemistry and Petroleum System Modeling in the Guyana Basin, offshore Suriname
Danny Schwarzer and Helle Krabbe
Maersk Oil, Copenhagen, Denmark
The Guyana Basin is a passive, continental-margin-style sedimentary basin which appears to have most of the elements required to become an important hydrocarbon province including a source rock of (Upper Albian) – Cenomanian-Turonian age. The basin presents typical ramp to prograding passive margin geometries, influenced by the Guyana Transform strike-slip tectonics and extends northwards from the coastal area of French Guiana, through Suriname, Guyana and the eastern part of Venezuela (Figure 1). The basin extends offshore where the sediment package becomes thicker as the basin grows deeper. The basin is bounded to the south by the outcrop of the Guiana Shield, a crystalline Proterozoic basement, and to the east by the Demerara High (Figure 1, targeted by well A2-1 and ODP leg 207 wells), which is a remnant of the West African continental crust.
The depositional history of the Guyana Basin is related to the break-up and subsequent opening of the Atlantic Ocean. The tectonic evolution of the margin can be subdivided into three stages;
i) Triassic–Jurassic Rift Phase
ii) Lower Cretaceous Strike Slip Influenced Passive Margin Phase
iii) Upper Cretaceous – Recent Passive Margin Phase.
A total of 32 wells have been drilled within the Guyana Basin of which 22 were drilled in the offshore Suriname sector between the 1960’s and the 1980’s (plus Tapir West 1 in 2008 by Repsol/Noble). Approximately half of the offshore wells were drilled in the near shore area close to the Tambaredjo Field. The vast majority of the wells drilled encountered oil and gas shows and the Abary-1 well, drilled in 1974 by Shell, demonstrated the presence of moveable hydrocarbons (Figure 1). The large Tambaredjo Field (>900 MMbbl STOIIP) and the much smaller Calcutta Field, both onshore Suriname, are located within the same hydrocarbon basin and are the only substantial discoveries to date. Recoverable reserves (Tambaredjo) have been estimated at 170 MMbbl (69 MMbbl remaining) reflecting a recovery factor of 19%.
New geochemical investigations on the source rock, its relation to petroleum occurrences and the integration with 3D petroleum system modeling, were aimed at a better understanding of the hydrocarbon migration and charge history within the offshore sector of Suriname. The predominant model of oil being generated in the central part of the Guyana Basin and having migrated 100-150 km up dip into shallow, almost unconsolidated Paleocene sands (Tambaredjo Field), is corroborated through new analyses.
The basin modeling study utilized a number of newly interpreted surfaces linked to latest high resolution biostratigraphy which have led to a refined burial history. The maturity of the Cretaceous source rock section is mainly governed by depositional trends in the Cretaceous and Tertiary where a 30-40 km northward build-out of the shelf occurred. The very thick and immature Upper Albian - Cenomanian section of the offshore well NCO-1 has been extensively sampled and formed the basis for source rock – oil correlation by biomarker and isotope analyses. Source rock specific kinetics was derived to better constrain timing and amount of petroleum formation in the modeling.
The reservoirs in the Tambaredjo Field are of Paleocene age, illustrating a significant stratigraphic as well as lateral component to the secondary migration history. Potential carrier beds along the modeled migration routes could be anything from mid-Cretaceous through Tertiary.
The Tambaredjo Field contains moderately biodegraded oils (API 15°-17°) that were also affected by evaporative loss. As a consequence, normal alkanes and acyclic isoprenoids are eliminated, but triterpanes and sterane biomarkers are left intact. The epimerisation at C20 in the C29 regular steranes has reached the thermal equilibrium value of 0.6 in most oil samples.
Similarly, the isomerisation of C29 steranes has resulted in %bb isomers of 0.55-0.6. Together, both parameters suggest the thermal maturity of the source rock at time of expulsion to be equivalent to 0.8-0.9% vitrinite reflectance.
The NCO-1 well Albian-Cenomanian source rocks are organic matter rich marine shales which can be classified as good to excellent oil-prone source rocks, containing predominantly type II kerogen (Figure 2). The deposits seem to become less prolific with depth, and a gradual facies change can be observed through the succession. The source rock extract samples show pronounced overall similarity comprising high levels of unresolved complex mixture (UCM), broad, light-end skewed distributions of normal alkanes extending to approximately nC40 with values of CPI close to 1 (0.8 - 1.1), and very high levels of acyclic isoprenoids.
On the detailed level, uppermost samples show higher levels of long-chain (waxy) n-alkanes relative to the lower samples that otherwise are mutually fairly similar. Pristane/phytane ratios show a systematic increase with depth from 0.99 to 2.1, concurrent with a decrease of the isoprenoid/n-alkane ratio. This is attributed to a gradual change in sedimentary facies towards less marly and more pure clastic deposition with depth compounded by the effects of slightly increasing thermal maturity with depth. Hence, the deeper parts of the succession are less rich in organic carbon and seem to contain a greater proportion of terrigeneous type III kerogen.
Geochemical data from an organic-rich Albian to Cenomanian section (immature) encountered in ODP leg 207 site 1258 to 1260 (Figure 1) suggest a widespread regional existence of an excellent source rock section.
Bulk kinetic determinations from the Upper Albian to Cenomanian source rock section in well NCO-1 essentially confirmed the similarity to the time/facies equivalent La Luna Fm. source rock (Venezuela) and were used as input to the PetroMod® modeling software.
With the probable established link, between oil and Cenomanian source rock as well as information on oil maturity and source rock specific kinetics, a 3D basin modeling study was carried out in order to assess the timing of source rock maturation, hydrocarbon generation, expulsion, subsequent migration and entrapment. Temperature and vitrinite reflectance data from offshore wells available were used to calibrate the 3D model.
As can be seen on Figure 1, the active source kitchen is located far to the Northwest of the Tambaredjo Field and continues further north. About 130 km from Tambaredjo Field, the Cenomanian source rock is within the main oil to wet gas window at present-day (0.7 – 1.3%VRr). Further northwards, the source rock has already generated its full potential and is over mature at present.
Significant hydrocarbon generation according to the specific kinetics started during the Late Paleocene (~55 Ma) within the deeper parts of the kitchen area, and around Late Eocene (~34 Ma) at kitchen flank positions (slope or shelf edge). Up to the end of the Oligocene (23 Ma), almost 75% of all convertible source rock kerogen in the deeper kitchen area had realized its full generation potential, whereas at flank positions only around 25% of the kerogen had been transformed to hydrocarbons. With enhanced burial during Miocene to present times, the central part of the Cenomanian kitchen enters the gas generation window (partly over mature), and only flank positions remain within the oil window.
Expulsion from the active source rock has been calculated to start around 50 Ma from deeper parts of the kitchen, and remains active until present from less mature areas around the slope break. Migration of hydrocarbons into the present-day shelf break area started around 25 Ma but was significantly accelerated during enhanced late burial from Late Miocene to present times. At present, we interpret that the shelf break is located above active source rocks within the main oil window, although a contribution of wet gas/condensate from more mature source rocks farther down the slope appears likely according to the chosen kinetics.
As the likely mature source rock is more than 100 km from the Tambaredjo Field, the charge has to occur via long distance migration. With a rough estimate of biodegraded 1Bbbl STOIIP at present, which could equate to pre-biodegraded 2Bbbls STOIIP (although it is not resolved whether biodegradation has taken place at the field, during migration, or likely both), one can only speculate on how many Bbbls entered the greater fetch area towards the Tambaredjo Field. Analogues of proven long-distance migration of that order of magnitude are rare, but presumably migration losses could be enormous and probably account for the much larger part of hydrocarbons injected into the system. Hence valid traps and top/lateral seals seem to be the critical factors to have kept (and keep) hydrocarbons from leaking out of the system.
Figure 1. Key wells drilled offshore Suriname and the main onshore fields Tambaredjo and Calcutta (key well NCO-1 is North Coronie-1). Dotted lines represent calculated vitrinite reflectance of the Cenomanian source rock section at present-day.
AAPG Search and Discovery Article #90091©2009 AAPG Hedberg Research Conference, May 3-7, 2009 - Napa, California, U.S.A.