Offshore Angola Research Articles

The deep structure of the South Atlantic Kwanza Basin — Insights from 3D structural and gravimetric modelling

Abstract We present results from 3D gravimetric modelling of the Kwanza Basin offshore Angola accomplished to investigate the deep crustal structure beneath the basin and discuss our findings with respect to their implications for the opening of the Central South Atlantic. The Kwanza basin is located in the southern part of the Central South Atlantic. Although the post-rift evolution of the Kwanza Basin is well studied, little is known about the basin's early history. This is mainly due to the missing knowledge of its crustal structure owing to the masking effect of an up to 4 km thick salt layer, which seismically obscures the underlying basement. To get an insight into the deeper structure of this part of the Angolan margin we combined 3D structural, isostatic and gravimetric modelling. 2D seismic reflection data was used to determine the structural setting and the configuration of the stratigraphic units in the sedimentary part of the basin, whereas its crustal structure was constrained by isostatic and gravity modelling. Our modelling results indicate that high density lower crustal bodies, similar to ones found in the Northern part of the central segment, are present in the Southern part, and thus seem to be a general feature of the crust of the Central South Atlantic. Thinning of the crust occurs gradually rather than in an abrupt manner and block faulting seems to have played a significant role during rifting as is indicated by a strongly structured upper crust. In contrast, we find little evidence for ductile thinning or exhumation of the deeper lithosphere as previously suggested for the northern segment of the central South Atlantic. In its Southern segment it appears more likely that magmatic intrusions prevented mantle exhumation by sealing crustal detachment faults and giving the margin a distinct magmatic signature.

Salt tectonics in the Sivas Basin, Turkey: outstanding seismic analogues from outcrops

The Sivas Basin in Central Anatolia is possibly the world’s finest open-air museum of salt tectonics structures. It is an elongated Oligo-Miocene sag basin that developed in an orogenic context above the Neotethys suture zone. A mid-Oligocene quiet period during convergence of the Arabian and Eurasian plates allowed the deposition of a thick sequence of evaporites. Erosion of the Taurus Mountains shed clastic sediments northwards over the evaporitic basin. Sediments and deformation propagated from the south, forming mini-basins and associated evaporite diapirs and walls. Following this quiet period, compression resumed in the early Miocene, enhancing the formation of gypsum overhangs and allochtonous sheets. The Sivas outcrops expose classic salt tectonics geometries associated with the development of diapirs: halokinetic sedimentary sequences along diapir walls, welds and evaporite sheets or canopies, minibasins, and overturned minibasin wings (overturned edges of minibasins). These exposures are some of the finest field analogues for classical petroleum provinces controlled by salt tectonics such as the Gulf of Mexico and offshore Angola. We illustrate seismic-scale structures and, in the vicinity of the evaporite bodies, interesting analogues for drilled structures where seismic data do not provide an image.

The role of tectonics and mass-transport complex emplacement on upper slope stratigraphic evolution: A 3D seismic case study from offshore Angola

Three dimensional seismic-reflection data of the mid-Pliocene-to-Holocene upper slope succession, offshore Angola, provide an opportunity to constrain the stratigraphic context, distribution, external morphology and internal strain within mass-transport deposits (MTDs). These data also allow an assessment of the impact that erosion and relief associated with MTDs have on upper slope stratigraphy and depositional patterns, and the role that MTDs play in achieving ‘grade’ on submarine slopes. The study area is dissected by a series of NW-SE-striking, thin-skinned, salt-detached normal faults, which bound a slope-perpendicular, intra-slope horst that divides the study area into two depocentres. Three main seismic packages and their six constituent units have been mapped across the study area and reveal that, during the initial stages of deposition, a series of MTDs were emplaced, the thickness and distribution of which are controlled by the intra-slope horst. Substantial volumes of substrate were removed and entrained into the parent flow, and significant and irregular relief (150 m) was developed along MTDs upper surface. This MTD-richpackage is interpreted to document a time when the slope was above grade, degradational processes dominated and sediment was trapped on the upper slope due to tectonic accommodation. Subsequent deposition was from either turbidity currents or and suspension fallout, at a time when the slope had begun to achieve ‘grade’ and depositional processes dominated. The associated depositional units display only minimal thickness variations with respect to the intra-slope horst, which had been ‘healed’ by this time; however, the unit displays pronounced and abrupt changes in thickness due to infilling of relief at the top of the preceding MTDs. The uppermost strata document a time when the slope was at grade and constructional process (i.e. aggradation and progradation) dominated. Deposition at this time was characterised by progradation of a mudstone-dominated, gullied slope system. This study highlights the role that tectonically- and mass transport-driven changes in bathymetry can have on upper slope accommodation and sediment dispersal. From a hydrocarbon exploration perspective this is critical, because tectonic and depositional accommodation provide a mechanism for capturing and trapping clastic sediments in an upper slope setting, which is otherwise typically associated with coarse-grained sediment bypass.

Evaluation and joint inversion of TTI velocity models with walkaway VSP in deep-water offshore Angola

We present a case study where a multitude of walkaway vertical seismic profiling (WVSP) data was employed in evaluating the accuracy of anisotropic velocity models used in a prestack depth migration (PSDM) project. We integrated the WVSP traveltimes with surface seismic PSDM residual moveout on migrated common-image gathers (CIG) in a joint inversion that determined the anisotropic model parameters. The resulting anisotropic model significantly reduces the mis-ties between the modeled and observed first arrivals in the various WVSP lines, in addition to the enhancement in CIG flatness and significant im-provement in imaging.

Startup of Pazflor Giant Offshore Angola Tackles Challenges From Two Reservoirs

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23176, ’Startup of a Giant,’ by Arnaud Constant and Lionel Ramat, Total E&P Angola, prepared for the 2012 Offshore Technology Conference, Houston, 30 April- 3 May. The paper has not been peer reviewed. The Pazflor development includes four reservoirs in Block 17 deep offshore Angola, which produce to a floating production, storage, and offloading (FPSO) unit through one Oligocene subsea loop and three Miocene lines connected to subsea separation units (SSUs) and subsea pumps, with associated-gas and water-injection facilities (Fig. 1). The startup of the Pazflor field required a response to three simultaneous challenges—startup of a large complex facility; flow assurance for two different reservoirs and oil qualities, an Oligocene field with light oil and Miocene fields with heavy viscous oil; and operating innovative Miocene subsea facilities with gas/liquid separation on the seabed. Startup Preparation Manning and Training. Although most of the production personnel were already experienced with FPSO operations, specific attention was given to training and a local training center at the Total E&P Angola offices was maximized. One of Pazflor’s innovations was the design and use of an immersive training simulator (Fig. 2). This simulator was generated from construction of a 3D model and represents all the topside facilities with realistic rendering. In this 3D environment, operators move virtually through a simple interface, allowing for familiarization with their future facilities. Because all equipment is tagged, the operator can easily link his work documents, such as process flow diagrams and piping and instrumentation diagrams, to the actual FPSO environment before its completion or without actually being there. This simulator also can be used to simulate procedures execution, either individually or in a group, thanks to preloaded scenarios. Startup Milestones and Initial Planning. The precommissioning, commissioning, and startup activities were structured according to milestones defined in the early project stage by field operations teams and included in relevant project-packages contracts. This breakdown by startup milestones was taken into account by the commissioning team from the early onshore commissioning stage and was later used to prioritize offshore construction, commissioning, and startup activities during the offshore campaign. Eighteen startup milestones were considered initially, focusing on utilities, oil production, water injection, gas injection, and export systems and covering prestartup, startup, and normal- operations phases. The facilities were split into systems and subsystems, with a total of 669 subsystems, each linked to a specific startup milestone.

Gas hydrate and free gas petroleum system in 3D seismic data, offshore Angola

Evidence of gas hydrate and free gas occurrences in a 3D seismic volume from the West-Central Coastal Province of the Congo Fan, offshore Angola, illustrates all the components of a complete petroleum system. Analysis and interpretation are based on the information in attributes calculated from three 3D time-migrated common-angle seismic volumes; the attributes include seismic amplitude, spectral components, dip magnitude, amplitude variation with angle, and instantaneous frequency. The source is organic-rich muds associated with late Cretaceous to early Tertiary channels, the migration paths are along growth faults, and the traps are partly defined by the gas hydrate stability zone (for the gas hydrate), partly by the bottom-simulating reflector (for the subhydrate free gas), and partly by faults (for both). The spatial distribution of free gas is further supported by the associated seismic bright spots, and also by the attenuation of high frequencies of P-waves that traverse the gas-saturated zone. Locally higher temperatures, associated with upward fluid circulation along fault zones, facilitate gas transmission through the gas hydrate and forms gas chimneys that extend to the sea floor.

Vertical evolution of fluid venting structures in relation to gas flux, in the Neogene-Quaternary of the Lower Congo Basin, Offshore Angola

The processes preceding the genesis of pockmarks and their subsequent evolution has been rarely studied since pockmarks were discovered in 1970. A high-resolution 3-D seismic survey from the continental slope of the Lower Congo basin allows us to study in detail the structures that developed before the formation of pockmarks, as well as their subsequent geometric evolution.This paper aims at reporting new type of fluid-related structures that relate to pockmarks. The objective of this research is to understand: 1) the evolution of these structures and their genetic relationship with pockmarks, and 2) how their morphologies may be influenced by changes in venting intensity over time.Pockmark and chimney structures in this survey are hosted within Late Miocene to Quaternary hemipelagites, above clastic reservoirs in a petroliferous basin. They are all associated with positive high amplitude anomalies (PHAAs) on seismic data. PHAAs are interpreted from their dramatically higher acoustic impedance relative to the background sedimentary values of the host units, and by their association with seismic pull-up effects. From their planform and cross-sectional geometry, PHAAs are primarily interpreted as being due to the development of methane-related carbonates but they may be associated with gas hydrates in one or two examples.Methanogenic carbonates form either by authigenic accumulation or by anaerobic methane oxidation (AMO) once upwardly migrating methane enters the sulfate-methane transition zone (SMTZ), typically within the first few tens of meters below the seabed. Therefore, vertical accumulations of PHAAS are interpreted to reflect the temporal evolution of methane flux migrating upward to reach the paleo-seabed or SMTZ. Timing of local scale fluid leakage can therefore be diagnosed by analyzing PHAAs at seep locations that occur in association with pockmark/chimney structures.A conceptual model for the evolution of different fluid venting structures is proposed here, and is based on the analysis of venting structures that we expressed by 3-D seismic reflections. In this model the main features are linked into a process-based sequence, culminating in the infill and termination of the pockmarks as fluid venting sites. Our model summarizes different rhythms of venting which are expressed by different types of PHAAs along with venting structures. Linear PHAAs and conduits inferred slow seeps. They can be succeeded by sub-circular PHAAs and shallow depressions which inferred slow to moderate seeps. Then the seep can become either a fast vent and terminated into a pockmark crater; or it can become less active and be sealed afterwards. Subsurface sediment fluidizations and remobilizations are likely to happen in the last case and are probably caused by hydrate dissociations.

The Namibian and Brazilian southern South Atlantic petroleum systems: are they comparable analogues?

Abstract Tectonic reconstructions made across the southern South Atlantic Ocean indicate a diversity of rift and drift basin characteristics on the conjugate margins that define them as different stratigraphic and structural entities. In terms of petroleum systems, the basins are not as unlike as some characteristics suggest. Given the lack of significant hydrocarbon discoveries to date south of the Walvis Ridge, doubts have been cast on the presence in this area of the prolific Lower Cretaceous lacustrine and marine source rock systems, which are well known in the Greater Campos Basin and offshore Angola. Oils and condensates from the basins south and north of the Walvis Ridge exhibit geochemical similarities suggesting that comparable source rock systems are present in both areas. The condensate geochemical analysis results from the Kudu Field in Namibia are compared with oils from marine and lacustrine sources in Brazil, indicating that the Kudu condensates are derived from at least two different source rocks. These results suggest that the underexplored basins offshore Namibia contain thermally mature Lower Cretaceous lacustrine and marine source rocks, offering a new frontier for petroleum exploration in Africa's southern South Atlantic.

First Polymer Injection in Deep Offshore Field Angola: Recent Advances in the Dalia/Camelia Field Case

Summary The polymer injection project on the Dalia field, one of the main fields of Block 17 in deep offshore Angola, is a world first in both surface and subsurface aspects. An in-depth integrated geosciences and architecture study culminated, in January 2009, in the start of polymer injection in one of the Dalia water-injection wells. The Dalia field is a high-permeability sandstone reservoir (> 1 D on average) and contains a medium-viscosity oil (1 to 11 cp under reservoir conditions). The key challenges of the project were to start polymer injection Very early in the field development (first oil was in December 2006) With much wider well spacing than in any other project Under high-salinity conditions (>25 g/L) With the specific logistics of a remote deep offshore area A phased approach has been retained in order to progressively derisk the project, starting from a single-well, short-duration injectivity test, followed by a full line injection in the three injectors of one of the reservoirs, and hopefully concluding with an injection extension. A single-well, short-duration injectivity test was successfully implemented in the first quarter of 2009. The Phase 1 project started on 8 February 2010 in the Camelia reservoir. Viscosified water was injected into one of the four injection lines of the Dalia field (average BSW) of 20% on the associated producers at beginning of Phase 1 polymer injection]. By December 2011, more than 5 million bbl of cumulative of polymer solution has been injected in the Camelia reservoir. The specificities of the Dalia field (large well spacing and low BSW at polymer-injection startup) mean a late response if the usual EOR monitoring techniques are applied. Various monitoring options were considered to verify the injected-polymer-solution properties in situ, and to accelerate the sanction for a full-field development. The studies concluded with a recommendation to drill a well to sample in situ the injected viscosified water. Location of the sampler well at a distance of 100 m from an injector, and the best timing to drill the well, were based on a 4D-seismic-data history match and waterflood-performance forecast.

A large-scale validation of OBN technology for time-lapse studies through a pilot test, deep offshore Angola

In early phases of offshore field development, repeated marine seismic surveys recorded with towed streamers have been successfully processed to image changes in reservoir fluids through time and hence have contributed to important reservoir development decisions such as elaborating future production and injection plans. In such cases, the negative impact of surface or underwater obstacles on the final image has been mitigated using undershooting strategies. Nevertheless, even in the most favorable cases, this has been achieved at the expense of 4D repeatability because short-offset illumination is missing in the undershoot survey and the azimuthal distribution within the offset classes becomes inconsistent with the base streamer data. As the field development proceeds, especially in deep offshore contexts, a complex network of in-sea and subsea installations is progressively put in place and the Health, Safety, and Environmental (HSE) issues related to seismic vessels or recording cables coming close to production facilities can no longer be neglected, making the conventional streamer or OBC acquisitions challenging, or simply not feasible. As a result, industry is proposing a “sea-floor receiver” solution with ocean-bottom nodes (OBN) for imaging and monitoring reservoir production below infrastructures. OBN are autonomous seismic recording systems deployed on the seafloor with remotely operated vehicles (ROVs). Previous tests and studies (Boelle et al., 2005; Ceragioli et al., 2006) have shown that OBN technology may be appropriate for reservoir monitoring. Here we present the results of the first large-scale OBN project completed by Total E&P Angola, between September 2008 and April 2009, over the deep-water Dalia Field, Block 17, with the aim of validating the use of this technology for 4D seismic reservoir monitoring.

Gas hydrate pingoes: Deep seafloor evidence of focused fluid flow on continental margins

Gas hydrates in the shallow subsurface form one of the largest reservoirs of methane in the global organic carbon cycle. Seafloor seeps and associated features represent the venting points of methane released from the shallow lithosphere to the hydrosphere and atmosphere. Here we document the discovery of seep-related seafloor mounds in the Kwanza Basin, offshore Angola, and employ high-resolution three-dimensional seismic analysis to unravel the subsurface plumbing system and the origin of mounds. Mounds with distinct morphologies and geophysical signatures illustrate different development stages associated with the formation and dissociation of shallow gas hydrate, linked to thermogenic fluid migration along salt diapir flanks draining deeply buried salt minibasins. The mounds are more than an order of magnitude larger than previously described submarine hydrate pingoes, and comparable to hydraulic pingoes commonly found in terrestrial periglacial environments, suggesting hydrate volumes of individual mounds up to 1.1 × 106 m3 (equivalent to 2.0 × 108 m3 of methane gas). The interpretation of seismically well-defined seep-related seafloor mounds brings new insight to the occurrence and development of concentrated near-surface gas hydrate accumulations and their relationship with thermogenic fluid migration and host sediment properties along continental margins.

4D pre-stack inversion workflow integrating reservoir model control and lithology supervised classification

We have run a 4D pre-stack inversion on seismic data acquired over a giant field located in deep water offshore Angola. The objective was to obtain dynamic information from 4D seismic data. The 4D inversion workflow started with a prestack 3D inversion of the baseline seismic survey. Using the relative P-wave velocity variations computed by warping, the initial impedance model of the baseline was updated in order to build the initial impedance model for the monitor survey. The update was done through a 4D mask which defines where impedance variations are allowed between the baseline and monitor impedance volumes. Due to the poor impedance discrimination between shales and water-bearing sands, where 4D effects may occur because of salinity differences between injected and aquifer water, reservoir model information was introduced in the mask in order to locate water-bearing sands. Ranges of relative impedance variations computed by the inversion were limited by 4D constraints derived from reservoir simulations before first oil and at the time of the monitor survey. 4D inversion brought sharper images compared to other 4D attributes. The high quality of the 4D inversion results evidenced by quantitative quality controls has opened the way to quantitative applications in reservoir management.

Polymer Injection in a Deep Offshore Field - Angola, Dalia/Camelia Field Case

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 135735, ’First Polymer Injection in a Deep Offshore Field - Angola: Recent Advances on Dalia/ Camelia Field Case,’ by Danielle Morel, SPE, and Michel Vert, Total E&P; Stephane Jouenne, SPE, Total Petrochemicals; and Renaud Gauchet and Yann Bouger, Total E&P Angola, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed. Key challenges of the polymer-injection project in the Dalia field, offshore Angola, were to start polymer injection: Very early in the field development With much wider well spacing than in other projects Under high-salinity conditions (>25g/L) With specific logistics of a remote deep offshore area Introduction The Dalia field is 130 km offshore Angola, with an estimated 1 billion bbl of recoverable oil. Water depth varies between 1200 and 1400 m, with reservoirs 800 to 1000 m below the seabed. Very-high-quality 3D-seismic data enabled mapping of the main reservoir structure, including sands and clay areas only 6 to 10 m thick. The channel complexes can be as thick as 100 m but are divided into heterogeneous sections with alternating layers of oil sands and clays. Permeability ranges from a few hundred millidarcies to several darcies, with an average permeability greater than 1 darcy. The reservoir temperature ranges from 45 to 56°C, and reservoir pressure is 215 to 235 bar. The 19 to 38°API oil is slightly undersaturated, with viscosity ranging from 1 to 11 cp at reservoir conditions. Water viscosity is approximately 0.5 cp at reservoir conditions. The field produces by energy from water injection, using a floating production, storage, and offloading (FPSO) vessel with 31 deviated or horizontal subsea injector wells and four injection flowlines. Generally, a single flowline is used to inject into several reservoirs and several systems. Maximum water injection is 405,000 BWPD. Production is achieved through four production lines and 37 producers. First oil was on 13 December 2006. The 240,000-BOPD plateau rate was reached after a few months and has been maintained since. Seawater is desulfated to prevent risk of barium sulfate deposit, and has been injected from the start. Produced water will be reinjected after water breakthrough. By June 2010, 25 producer wells were connected and water breakthrough had occurred in several wells, with water cut ranging from a few percent to more than 40%. The current water-injection salinity is approximately 50 g/L.

Hydrocarbon plumbing systems of salt minibasins offshore Angola revealed by three-dimensional seismic analysis

Analysis of three-dimensional seismic data from the lower Congo Basin, offshore Angola, reveals numerous fluid-flow features in the Miocene to Holocene succession and the potential for large, shielded traps underneath basinward overhanging salt structures. The fluid-flow evidence includes present-day sea floor pockmarks clustered above salt structures, Pliocene–Pleistocene stacked paleopockmarks and Miocene pockmark fields. Other fluid-flow features include high-amplitude cylindrical pipe structures 60 to 300 m (197–984 ft) wide and 25 to 300 m (82–984 ft) high within lower and middle Miocene strata, thick (150 m [492 ft]) high-reflectivity zones within the Pliocene succession associated with bottom-simulating reflections, and subvertical low-amplitude chimneys originating from the deeper section (1 km [0.6 mi] beneath the sea floor). The Miocene pockmark fields occur at a specific horizon, suggesting a regional fluid expulsion event at ca. 12 Ma, and the Miocene fluid-flow regime is interpreted to be dominated by thermogenic fluids supplied via carrier beds and leaking vertically above structural highs. The Pliocene–Pleistocene fluid-flow regime was dominated by short-distance vertical fluid migration and expulsion related to early stage diagenetic processes involving biogenic methane and pore water. The present-day fluid-flow regime is inferred to be dominated by thermogenic fluids primarily controlled by kilometer-scale salt-flank-controlled migration. The study emphasizes the use of seismically imaged fluid-flow features in hydrocarbon systems analysis by documenting the evolution of an overburden plumbing system through time, involving several fluid types and flow regimes, depending on the spatiotemporal availability of thermogenic and diagenetic fluids and the tectonostratigraphic occurrence of aquifers, traps, and seals.

Real-Time Reservoir Management in a High-Cost Deepwater Environment - Greater Plutonio

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 128542, ’Greater Plutonio - Real-Time Reservoir Man age - ment in a High-Cost Deepwater En vironment,’ by Dave Booth, SPE, and Pedro Sebastiao, SPE, BP plc, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. The paper has not been peer reviewed. Greater Plutonio is a large subsea development with a planned first phase of 43 high-rate subsea wells. A relatively low level of classical field appraisal was performed because of high costs. Innovative subsurface management was required to reduce substantial uncertainty during the development phase. Remote access to real-time data enabled making better decisions faster and reducing the number of field staff. Introduction The Greater Plutonio fields (Plutonio, Cobalto, Galio, Cromio, and Paladio) were discovered offshore Angola between 1999 and 2000 and are Upper Oligocene turbidite reservoirs. Changes in fluid and lithology in the semiconsolidated reservoir rocks manifest themselves as distinct changes in seismic response. Water depths are between 1200 and 1400 m, and a relatively dispersed resource base resulted in the most viable development concept being a 100% subsea-well development with multikilometer-scale well spacing produced through a large floating production, storage, and offloading (FPSO) vessel. The initial development phase of 43 wells, plus up to 25 additional infill and sidetrack wells, was the largest subsea development undertaken by the operator. Of the initial 43 wells, 23 are injection wells, and most are completed across multiple reservoirs with full sand control. At the time of writing this paper, 34 wells had been drilled, and subsurface outcome was largely as expected. All reservoirs are waterflooded, with approximately one-half the injection wells having downhole flow control (DHFC) to improve injection management. The high-porosity rocks often have permeability exceeding 1 darcy, which, combined with high-gravity oil, provide a favorable mobility ratio and very efficient displacement. Recovery factors in some reservoirs should exceed 50%. The associated gas is injected through two wells in the Plutonio field to provide pressure support. This process will continue for 3 to 4 years after field startup, until gas export is available after commissioning of the Angola liquefied-natural-gas project. All of the production wells have openhole-gravel-pack (OHGP) completions, some with openhole completion lengths of up to 800 m. Although confidence to sanction the project was provided by the high-quality seismic data, a high degree of subsurface uncertainty remained (e.g., reservoir connectivity). Appraisal drilling was conducted in only one of the five fields. Therefore, a significant amount of subsurface appraisal was loaded into the development stage. The understanding and management of subsurface uncertainty has been crucial for the development, with early and effective data collection by use of wireline, logging-while-drilling (LWD), and coring programs; preproduction well-interference testing; and real-time data acquisition during the ramp-up period.

WATS it take to image an oil field subsalt offshore Angola?

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.

Extreme weathering/erosion during the Miocene Climatic Optimum: Evidence from sediment record in the South China Sea

Investigating the interplay between continental weathering and erosion, climate, and atmospheric CO2 concentrations is significant in understanding the mechanisms that force the Cenozoic global cooling and predicting the future climatic and environmental response to increasing temperature and CO2 levels. The Miocene represents an ideal test case as it encompasses two distinct extreme climate periods, the Miocene Climatic Optimum (MCO) with the warmest time since 35 Ma in Earth's history and the transition to the Late Cenozoic icehouse mode with the establishment of the east Antarctic ice sheet. However the precise role of continental weathering during this period of major climate change is poorly understood. Here we show changes in the rates of Miocene continental chemical weathering and physical erosion, which we tracked using the chemical index of alteration (CIA) and mass accumulation rate (MAR) respectively from Ocean Drilling Program (ODP) Site 1146 and 1148 in the South China Sea. We found significantly increased CIA values and terrigenous MARs during the MCO (ca. 17–15 Ma) compared to earlier and later periods suggests extreme continental weathering and erosion at that time. Similar high rates were revealed in the early‐middle Miocene of Asia, the European Alps, and offshore Angola. This suggests that rapid sedimentation during the MCO was a global erosion event triggered by climate rather than regional tectonic activity. The close coherence of our records with high temperature, strong precipitation, increased burial of organic carbon and elevated atmospheric CO2 concentration during the MCO argues for long‐term, close coupling between continental silicate weathering, erosion, climate and atmospheric CO2 during the Miocene.

Four-dimensional analysis of the Sembo relay system, offshore Angola: Implications for fault growth in salt-detached settings

Subsurface mapping of several relay ramps from a raft-related fault array in the lower Congo Basin, offshore Angola, reveals a full spectrum of fault linkage styles. A comprehensive three-dimensional geometric and kinematic appraisal of a more complex relay system within the fault array, the Sembo relay system (SRS) highlights differences with current structural models of relay ramp genesis, evolution, and breaching. The SRS is a rearward (upper ramp) breached relay system with a maximum fault overlap and spacing of 9500 and 3600 m (~31,000 and 11,800 ft), respectively. This system is characterized by a structural geometry that becomes increasingly complex with depth as the relay system is gradually assimilated into the structural architecture of a separate and structurally deeper fault system. A detailed kinematic appraisal of the SRS indicates that the throw patterns on the frontal and rearward segments are intrinsically different. Throw backstripping reveals different initiation ages for the rearward and frontal segments of about 5.5 and 2.5 Ma, respectively. Mutual overlap is estimated to first occur about 2.5 Ma at the 5.0 Ma structural level, with fault linkage and ramp breaching occurring subsequently. The SRS therefore represents a complex amalgamation of faults that have each developed independently at different times. The genesis and evolution of the SRS have been governed through time by both salt withdrawal and associated fault detachment histories, in conjunction with increased Congo Fan progradation and sedimentation rates and phases of tectonic tilting of the underlying salt detachment surface.

Three-dimensional modelling and interpretation of CSEM data from offshore Angola

ABSTRACT In 2000, a large marine controlled-source electromagnetic (CSEM) calibration survey was acquired by Statoil as a part of a CSEM evaluation project over known hydrocarbon (HC) reservoirs offshore Angola. The electric field magnitudes measured at the seafloor above the HC reservoirs are 1.5 to 3 times higher compared to the synthetic background responses and ‘off-reservoir’ measurements. The relative strength of the electric field measurement above a salt structure is very strong (normalized magnitudes stronger than 3) compared to the background response. Modelled responses obtained from three-dimensional finite difference time-domain forward modelling, based on seismic and petrophysical data, show good agreement to the measured responses over the HC reservoirs. The modelled response after introducing a shallow resistor to the 3D model explains the strong CSEM anomaly measured in the NE part of the study area with no proven HC reservoir. The 3D forward modelling is also used to predict the sensitivity to the resistivity of the undrilled structure in the SE part of the study area, where no CSEM data were acquired. Integration of structural information interpreted from seismic data and resistivity values estimated from well logs significantly improves the subsurface geo-resistivity modelling and complements the offshore Angola CSEM data interpretation.

Incorporating uncertainty into geological and flow simulation modelling in Chevron: application to Mafumeira, a pre-development field, Offshore Angola

Abstract In this paper, we describe a reservoir-modelling case history of Mafumeira, a Chevron-operated field located in Offshore Angola. The field has only six well penetrations and lies within the closure of nearly 60 square kilometres; the purpose of the study was to capture a range of subsurface uncertainties for evaluation of the development options. We used a Depositional Facies Modelling scheme utilizing recent developments in Multiple Point Geostatistical Simulation and reservoir property uncertainty analysis to generate five static reservoir models. After scale-up, flow simulations were conducted on each model for different field development options using a Design of Experiments (DoE) methodology and a preferred development option was selected. The geology of Mafumeira field is complex. The multiple point geostatistical simulation used a training image consisting of seven depositional facies. The training image is a 3D conceptual model of the facies present and the facies associations; it captures complex spatial relationships between multiple facies, and non-linear shapes such as sinuous channels. The facies simulation was conditioned by a facies probability cube, which permitted the use of a single training image for different stratigraphic intervals of the reservoir, with different combinations and proportions of the seven facies. Multiple versions of the facies probability cube were produced to model the uncertainty in the occurrence of reservoir quality rock units. In modelling the reservoir properties, uncertainties in porosity, permeability and water saturation (‘PKS’) were taken into account. Five models were produced reflecting the combinations of high- and low-case reservoir facies, high- and low-case PKS properties and an intermediate-case. The high-, intermediate- and low-case models were then dynamically tested to ensure different flow behaviours, prior to upscaling, and the flow behaviours compared to analogue producing fields. In order to utilize DoE simulation, upscaling of the five fine-grid models was required. Flow-based simulation was chosen as the best tool to validate the behaviour of the coarse-grid models against the fine-grid models. However, this effort demonstrated that the conventional scale-up methods utilized in other reservoir models did not adequately capture the behaviour of the fine-grid models in this heterogeneous reservoir. A new method that adjusts the Dykstra–Parsons coefficient was investigated and successfully employed to tune the coarse-scale models. Twelve development alternatives for the field were defined and deterministic economics, based on results from the mid-case simulation model, were run in order to narrow down the number of alternatives to be carried forward into probabilistic analysis to five. The DoE approach allowed us to undertake a thorough evaluation of the key subsurface uncertainties and design an overall development plan. The probabilistic simulation results along with full Decision Analysis (DA) allowed us to identify a phased development, which would mitigate potential downside risks while preserving the ability to capture upside potential.