Abstract: Constraining basin thermal history is a key part of reservoir characterization in carbonate rocks. Conventional palaeothermometric approaches cannot always be used: fluid inclusions may be reset or not present, while δ 18 O palaeothermometry requires an assumption on the parent fluid composition. The clumped isotope palaeothermometer, however, is a promising technique for constraining the thermal history of basins. In this study, we test if clumped isotopes record temperatures of recrystallization in deeply-buried dolomitic reservoirs, through comparison with fluid-inclusion data. The studied reservoir is the Cretaceous Pinda Formation, offshore Angola, a deeply-buried dolomitized sedimentary carbonate hydrocarbon reservoir. It provides an ideal test case as samples from industry wells are available over a relatively wide burial depth range of c. 2000–4000 m below seafloor (mbsf) and the constituent dolomites are relatively homogeneous. Across this depth range, fluid-inclusion homogenization temperatures for the Pinda Formation record a range of temperatures from c. 110 to 170°C, increasing with depth. These closely match present-day ambient well temperatures, indicating recent resetting of the fluid inclusions. Clumped isotopes, however, record temperatures significantly ( c. 20–60°C) below fluid-inclusion and well temperatures for the seven samples analysed. The deepest five samples ( c. 2800–3700 mbsf) record clumped isotope temperatures of around 100–120°C, interpreted to represent a deep burial recrystallization event responsible for a massive (re)dolomitization of the reservoir. The lower clumped isotope temperatures (65 and 82°C) of the shallower (2055 and 2740 mbsf) samples are interpreted to represent physical mixing of two dolomite generations due to incomplete burial recrystallization of an early shallow dolomite. Determination of temperature through clumped isotopes allows calculation of the parent fluid δ 18 O values. In the five deepest samples, the fluid δ 18 O values of 3.7–6.5‰ cluster around the modern-day porewater composition (5‰), suggesting that burial dolomitization occurred in the presence of evolved brine. Mineral δ 18 O values of c . −7 to −4.5‰ are lower than pristine Cretaceous marine dolomite and are in accordance with burial recrystallization. Clumped isotopes are therefore interpreted to record temperatures corresponding to open-system burial recrystallization events. This study shows that clumped isotopes are a valuable tool in characterizing the thermal history of deeply-buried (>2000 m) carbonate hydrocarbon reservoirs. Supplementary material: All standard and sample data are available at https://doi.org/10.6084/m9.figshare.c.3945184

Abstract: Reaction transport modelling (RTM) has been successfully used to simulate dolomitization and to predict the lateral extension of dolomitized bodies as potential hydrocarbon reservoirs in the subsurface as well as to give insights into the dolomitization process itself. Geological configurations that have been tested include reflux dolomitization, thermal convection and dolomitization in compactional burial settings. In this study the hydrothermal dolomitization model has been tested with a RTM approach where a limestone reservoir in an intermediate burial setting is fluxed in the presence of deep feeding faults. Hydrothermal fluids migrate upwards from the deep basin areas through extensional fault conduits reaching more permeable levels in the reservoir. The fluids enter the primary interparticle porosity and dolomitize the limestone creating moldic and vuggy porosity. The simulations demonstrate the importance of faulting in this dolomitization process. An effective control on dolomitization is thus exerted by the permeability distribution. Moreover, the type and reactivity of the fluids entering the limestone reservoir exert important controls on the extent of the dolomite bodies.

Abstract The rifted continental margins off Brazil and West Africa encompass several morphological distinct regions that resulted from the plate separation and subsequent drift of South America and Africa. The main building blocks that controlled the development of the Atlantic-type continental margin basins consist of prerift, synrift, and postrift tectonic stages, and these events determined the basin infill. Oceanic fractures created by transform faults that indent the continental margins form basement highs that ultimately define the tectonic edges of the continental margin basins. These boundaries are involved in the marginal plateaus, marginal banks, and characteristic marginal volcanic ridges. Major petroleum producing provinces are situated in the rifted margin salt basins and also in the equatorial transform margin basins without salt. In the salt basins, the continental slope and rise are characterized by the development of massive salt walls that delineate minibasins that were in-filled with deep-water sediments. The hydrocarbon production from these deep-water reservoirs are mainly from postsalt Tertiary and Upper Cretaceous turbidite sands, plus added production from the cluster trends of presalt carbonate microbialite reservoirs. These reservoirs are all mainly sourced by Lower Cretaceous synrift lacustrine strata, but Upper Cretaceous source rocks have also been identified in the South Atlantic salt basins. The equatorial conjugate transform margin basins are also characterized by minor salt deposition in some regions (such as the Ceará basin). These basins produce hydrocarbons from combination traps of Tertiary and Upper Cretaceous turbidite reservoirs. All of the deep-water basins are influenced either by salt or shale tectonics and related to episodic volcanism. In the southernmost South Atlantic, volcanism dominates the conjugate margins, as indicated by thick wedges of seaward-dipping reflectors. There are two main types of South Atlantic continental margins: The transform margins shaped by the large offset equatorial fracture zones and in which the transverse structural lineaments are predominant, except for preexisting structuring that is not related to the Cretaceous transform directions. In these basins, where salt is absent, the typical exploratory play includes combination traps with turbidite reservoirs, generally exhibiting remarkable bright-spots amplitudes that reflect the associated deep-water channels and stratigraphic pinch-outs. The rifted conjugate margins shaped by salt tectonics, which extend from Sergipe-Alagoas to the Santos basin in Brazil and the corresponding conjugate margin basins from Cameroon to Angola. Here, the typical plays are predominantly associated with autochthonous salt. The salt basins account for most of the South Atlantic’s offshore petroleum production. The postsalt and presalt petroleum yields are explained by lacustrine source rock maturation during Tertiary times. Hydrocarbon migration is either into the synrift reservoirs proper or through salt windows into the postrift/postsalt reservoirs of mid-Cretaceous to Miocene. In the presalt plays, the synrift source rock and the carbonate reservoirs in the sag basin are capped either by massive salt or by a thick layered highly mobile evaporite sequence. Future exploration will need to tackle the ultra-deepwater provinces near the continent-ocean boundary, where there are several potential tectonic, structural and stratigraphic targets.

Abstract The imaging of deep-water turbidite slope-channel systems in Offshore Angola has improved greatly during the past decade through the acquisition of high resolution seismic surveys. Within the Marte Field, located in Block 31 NE, high resolution seismic data provides greater definition of the internal stratigraphy of third-order channel complexes. Fourth-order channel cuts and associated facies, including muddy slumps, within the third-order systems have been mapped in considerable detail. Better definition of the internal depositional architecture reveals a high degree of heterogeneity within the channel systems and offers insights into the fluid dynamics of Marte Field reservoir systems. Improvements on data quality also enable the quantitative use of AVA and inversion products for populating static models with realistic reservoir properties. Given the sparse well data available for rock property calibration, the integration of high-resolution seismic facies mapping into geocellular models has allowed us to constrain further property populations based on well logs and analogs-calibrated net-to-gross estimates. Combining alternate facies descriptions within different polygons is used to provide alternate fluid dynamic scenarios and cases. The range of models produced allows us to establish a reservoir operating envelope that is being used for development well planning and for reservoir management decisions.

Abstract The infill history of a salt withdrawal minibasin in the contractional domain of the gravity-driven salt system on the Angolan passive margin has been reconstructed using a high resolution three-dimensional seismic data-set. Well-constrained biostratigraphy has allowed calculation of the growth rate of the basin-bounding structures. Within the interval of stratigraphy investigated, the depositional style of sediments preserved in the basin has changed in response to changes in the rate of growth of the coeval, adjacent salt structures. During the early part of the basin history, sedimentation in the slope system was dominated by a series of erosional channel complex systems, which are 1-3 km wide and contain a preserved infill 100-200 m thick. The creation of sea floor topography by contemporaneous salt movement and the development of salt-cored anticlines caused the channels to be deflected, diverted, off-set, or deeply incised as they interacted with the developing slope topography. Subsequent salt movement, and a concomitant increase in the growth rate of the basin-bounding anticlines, led to more elevated topography and the development of extensive slumping of sediment into the basin centers, forming large mass transport deposits. As salt movement continued, the basin became largely enclosed; bound by a well-developed salt wall to the west and a series of complex salt structures to the east, where salt-cored anticlines developed laterally into salt diapirs. These complex structures controlled the flow pathways of sediment both into and out of the basin. The growth rate of the structures constraining the western margin of the basin slowed at this time, and as a result, sediment transported from the east by feeder channels formed ponded fan systems comprised of sheets of sand each formed by multiple small channels. Understanding the impact that active growth structures can have on sediment distribution and facies development is invaluable in the exploration and production of oil and gas. In this area, the association of the channels with the structure has formed reservoir-trap combinations for four major oil fields, Plutao, Saturno, Marte and Venus, being combined together as the PSVM development. In each field, the specific interaction of the channels with the growing topography has controlled the channel architecture and facies development; this has meant that different development plans, risks and uncertainties are required for each field.

Abstract BP's exploration success in deepwater Block 31, offshore Angola, has been driven by conventional narrow-azimuth 3D seismic data coupled with the latest available imaging algorithms. However limitations in these data are now apparent and the data is deemed insufficient for the appraisal and development of the subsalt discoveries in the western part of the block. 3D acoustic finite-difference modelling was applied to Block 31 to evaluate the potential data quality uplift from a wide-azimuth towed streamer (WATS) survey. Results showed that a significant improvement in data quality is possible. The modelling also investigated key acquisition variables (acquisition direction, sail line separation, number of tiles, cable length) to arrive at a solution that optimized both data quality and cost. Acquisition of this survey began in December 2008 and it is expected to complete in August 2009. This is the first WATS seismic survey outside the Gulf of Mexico and the first in Angola.

Abstract Offshore Angola is a world-class petroleum province with oil production in excess of 2 million barrels per day in 2008. Exploration activity in the offshore commenced in earnest in the early 1990s, with the contractual terms permitting only the production of oil. There is no provision for the production of gas. However, there have been several discoveries of associated and non-associated gas, by accident, in the search for oil. Gas will play a significant role in the future of Angola. A new gas business is emerging. Demand from a new liquefied natural gas (LNG) plant, the emerging Soyo industrial complex and the growing domestic and industrial sectors have created a business environment whereby near-term gas exploration, development and production is a critical need for the future of Angola. What is the gas resource potential of Angola: from mature basins to new frontiers? Is there potential for new giant gas fields? Conceivably, there are multiple petroleum system opportunities. This paper provides some insights into the petroleum geoscience exploration efforts being made by Angola's national gas company, Sonangol Gas Natural. The focus of this paper will be on the exploration for non-associated gas. The associated gas potential of Angola is relatively well known and will not be discussed. Sonangol Gas Natural has an extensive offshore seismic and well database. This is characterized by a series of merged, high-quality 3D seismic surveys that facilitate the application of the most advanced technologies. In excess of 130 offshore wells have encountered gas at multiple stratigraphic levels. However, the interior basins are a truly frontier province and data are limited to a regional gravity and magnetic dataset and surface rock outcrops. The conventional thermogenic petroleum systems of the offshore and the adjacent onshore Lower Congo, Kwanza/Benguela and Namibe basins are relatively well known. These comprise a Late Cretaceous and Cenozoic post-salt petroleum system, and an Early Cretaceous and Late Jurassic pre-salt petroleum system. The primary emphasis of the exploration effort in these basins is to better understand and to delineate the gas kitchens for the known source horizons, for example Malembo, Iabe (post-Aptian salt) and Bucomazi (pre-Aptian salt) formations. Biogenic gas plays constitute an unconventional petroleum system that requires different exploration concepts from those of conventional thermogenic petroleum systems. The principal challenges are to identify palaeo-gas hydrates, reservoired in Miocene clastics, to define the biogenic gas fairway and to evaluate the play elements of reservoir, trap and seal. The geological conditions necessary to establish a biogenic gas play in the deepwater and ultra-deepwater will be examined. The interior Owambo, Okawango and Kassanje Basins have no proven petroleum systems. However, some new play concepts of Neoproterozoic age will be presented using possible analogues worldwide. The future demand for gas will increase globally. New developments in LNG will change the world of gas. Angola will be a key player.