Offshore Congo Research Articles

Paleostress evolution of the West Africa passive margin: New insights from calcite twinning paleopiezometry in the deeply buried syn-rift TOCA formation (Lower Congo basin)

Accurate characterization of hydrocarbon reservoirs requires a good understanding of the paleostress history of their host sedimentary basin. This study aims at reconstructing the paleoburial and paleostress history of the syn-rift Barremian TOCA Fm. in the Lower Congo basin (West African margin). Two oriented borehole cores drilled offshore Congo were investigated using stress inversion techniques applied to calcite mechanical twins to constrain paleostress orientations and magnitudes. The inversion of calcite twins was performed on a widespread early diagenetic cement (~129 to ~113 Ma) and revealed that the TOCA Fm. has undergone a complex polyphase stress history, including (1) extensional stress regimes with vertical σ1 and horizontal σ3 trending NE-SW and WNW-ESE (N100) associated with the rifting episode preceding the opening of the South Atlantic (130 to 112 Ma), and with mean differential stresses of ~47 MPa for (σ1-σ3) and ~ 20 MPa for (σ2-σ3). The early N100 extension is associated with the development of normal faults striking N-S that likely reactivated inherited basement structures. The direction of extension evolved during the Barremian into the main NE-SW extension marked by the dominant normal faults striking NW-SE. (2) Compressional and strike-slip stress regimes with horizontal σ1 oriented ~N-S possibly related to the far-field intraplate transmission of orogenic stresses generated at the distant Africa-Eurasia plate boundary at ~67–60 Ma, and with mean differential stresses of 40 MPa for (σ1-σ3) and 28 MPa for (σ2-σ3). (3) Compressional and strike-slip stress regimes with horizontal σ1 oriented ENE-WSW to ~E-W that we tentatively relate to the mid-Atlantic ridge push and prevailing since ~15 Ma onwards, associated with mean differential stresses of ~45 MPa for (σ1-σ3) and ~ 18 MPa for (σ2-σ3). Our results reveal that the TOCA Fm. recorded mainly far-field stress effects that could be related to interactions between the African plate and surrounding plates, and that divergent passive margins may experience a complex tectonic history including both extensional and compressional events.

Distinguishing the influence of sediments, the Congo River, and water-mass mixing on the distribution of iron and its isotopes in the Southeast Atlantic Ocean

Iron (Fe) is an essential micronutrient for primary production, and Fe isotopic composition (δ56Fe) has become a widely used oceanographic tool for determining sources and evaluating the biogeochemical cycling of dissolved Fe (dFe) in the oceans. Here, we present dFe concentrations and δ56Fe from three unique oceanographic settings (a river dominated margin, a highly productive coastal upwelling margin, and a meridional open ocean transect) collected during the South Atlantic GEOTRACES cruise GA08 along the Namibian-Congo margin. In the North, the offshore Congo River plume dominates the surface ocean, resulting in elevated surface dFe concentrations up to 1000 km from the river mouth, corresponding to increasing δ56Fe values (+0.33 to +0.95‰) with distance from the river outlet. We attribute this unusual and extensive offshore delivery of heavy Fe to dFe preservation by complexation with organic ligands, coupled with rapid off-shelf advection. In the South, the highly productive Benguela Upwelling System produces oxygen depleted to seasonally anoxic bottom waters on the continental shelf, resulting in extremely high subsurface dFe concentrations (up to 42 nmol kg-1) and remarkably light δ56Fe values (as low as -3.31‰), characteristic of dFe(II) production and mobilization via reductive dissolution of Fe oxyhydroxides in sediments. Away from the continental margins, surface waters carry predictably low dFe concentrations (∼0.1 nmol kg-1), associated with isotopically heavy Fe linked to dust deposition and biological uptake. In subsurface waters, and away from Fe sources, we find a remarkably coherent relationship between water masses and dissolved δ56Fe signatures along the GA08 section. Using δ56Fe data from GA08 and water mass analysis, we assign endmember signatures of -0.12 ± 0.02‰ for AAIW, +0.71 ± 0.09‰ for NADW, and +0.35 ± 0.12‰ for AABW. Overall, we find that the distribution of δ56Fe in the South Atlantic can largely be explained by water mass mixing, with some overprinting by local processes and sources, suggesting that dissolved δ56Fe signatures can be used as tracers of deep ocean Fe transport.

Seismic Dispersion and Attenuation in Fluid‐Saturated Carbonate Rocks: Effect of Microstructure and Pressure

AbstractThe frequency dependence of seismic properties of fully saturated rocks can be related to wave‐induced fluid flows at different scales. The elastic dispersion and attenuation of four fluid‐saturated carbonate rocks, with different microstructures, have been measured over a broad frequency range in the laboratory. The selected rocks were a presalt coquina from offshore Congo, an Urgonian limestone from Provence (France), and an Indiana limestone either intact or thermally cracked. The selected samples present a variety of pore types characteristic of carbonates, and their link with potential squirt flow dispersion was investigated. To cover a broad frequency range, forced oscillations (0.004 to 100 Hz) and ultrasonic (1 MHz) measurement techniques were performed in a triaxial cell, at various differential pressures, on the samples saturated by fluids of different viscosity. Both hydrostatic and axial oscillations were applied in order to get the different dynamic moduli. For all our samples, the drained/undrained transition and the squirt flow mechanisms were characterized experimentally, in terms of amplitude of dispersion, amount of viscoelastic attenuation, and frequency ranges. Biot‐Gassmann's theory was found to apply mainly at seismic frequencies (10–100 Hz). A potential correlation between pore type and possible squirt flow dispersion was investigated. Intragranular microporosity, with either a rimmed or uniform distribution, does not seem to generate any substantial dispersion. On the other hand, cracked intergranular cement and uncemented grain contacts seem to generate substantial squirt flow dispersion, at respectively seismic and sonic log frequencies.

U-Shaped Re-Entry Drilling Revitalizes Depleted Reservoirs Offshore Congo

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191436, “Extended-Reach U-Shaped Re-Entry Drilling in Shallow, Depleted Fractured Reservoirs in Congo’s Oldest Offshore Oil Field,” by Mike Tony Chembou, Bruno Valeri, Lois de Crevoisier, Michel Akue, and Vincent Rodet, Perenco Congo, and Gabriele Ghia, Achille Mouamba, and Ali Lazzem, Schlumberger, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost-effective manner. The solution selected was to drill U-shaped side tracks (inclination at total depth=115°) from the original boreholes on an existing platform at a water depth of 60 m. The objective was to create a second drainage area. The project team used innovative, low-cost techniques to overcome many challenges. Geological Context and Objectives Under 27 platforms (four to five well-heads each), an accumulation of heavy, viscous oil is trapped in three reservoir layers. The field was produced with a combination of cold mode followed by a period of hot mode from steam injection. The consequence is a depleted (0.3-sg) and highly steam-fractured reservoir where fluid loss presents one of the primary challenges for infill development. The pilot project consists of re-entering the current producers and then deepening them in a U shape to access the same shallow reservoirs more than 200 m away from the initial production leg. All reservoirs share the same water table identified below an impermeable formation underneath the target layers. To avoid water breakthrough, the trajectories were planned with up to 18°/30 m to prevent the well from entering the water-bearing layer, with minimum 30-m true vertical depth standoff from the oil/water contact. Well Design and Architecture The well architecture is selected to match the existing mother-well construction. All selected re-entry candidates are producing wells showing the following well architecture: 9 5/8-in. casing set as intermediate casing at approximately 100 m measured depth (MD) below the rotary table A mixed string composed of cemented blank 7-in. casing and uncemented 7-in. slotted liner in front of the pay zones. An external casing packer (ECP) was installed between the two strings, and a cementing job was performed above the ECP. The float shoe at the bottom, therefore, was uncemented and prone to be untorqued during re-entry The completion system consisted of progressive-cavity-pump or sucker-rod-pump strings, depending on the wells. To fulfill the geological and reservoir objectives, the wells were re-entered by drilling a 6-in. hole section from a 7-in. float shoe to the U-shaped total depth before a 4½-in. liner was run. The sand-face completion evolved slightly from the first two wells (blank perforated) to the last three wells (slotted liner).

Spider structures: records of fluid venting from methane hydrates on the Congo continental slope

Fluid seepage features on the upper continental slope offshore Congo are investigated using multi-disciplinary datasets acquired during several campaigns at sea carried out over the last 15 years. This datasets includes multibeam bathymetry, seismic data, seafloor videos, seafloor samples and chemical analyses of both carbonate samples and of the water column. Combined use of these datasets allows the identification of two distinctive associations of pockmark-like seabed venting structures, located in water depths of 600–700 m and directly above a buried structural high containing known hydrocarbon reservoirs. These two features are called spiders due to the association of large sub-circular depressions (the body) with smaller elongate depressions (the legs). Seismic reflection data show that these two structures correspond to amplitude anomalies locatedca. 60–100 ms below seabed. The burial of these anomalies is consistent with the base of the methane hydrate stability domain, which leads to interpret them as patches of hydrate-related bottom-simulating reflection (BSR). The morphology and seismic character of the two structures clearly contrasts with those of the regional background (Morphotype A). The spider structures are composed of two seafloor morphotypes: Morphotype B and Morphotype C. Morphotype B makes flat-bottomed depressions associated with the presence of large bacterial mats without evidence of carbonates. Morphotype C is made of elongated depressions associated with the presence of carbonate pavements and a prolific chemosynthetic benthic life. On that basis of these observations combined with geochemical analyses, the spider structures are interpreted to be linked with methane leakage. Methane leakage within the spider structures varies from one morphotype to another, with a higher activity within the seafloor of Morphotype C; and a lower activity in the seafloor of Morphotype B, which is interpreted to correspond to a domain of relict fluid leakage. This change of the seepage activity is due to deeper changes in gas (or methane) migration corresponding to the progressive upslope migration of fluids. This phenomenon is due to the local formation of gas hydrates that form a barrier allowing the trapping of free gas below in the particular context of the wedge of hydrates.

Technology Focus: Offshore Production (November 2014)

Technology Focus Shallow-water offshore production began before 1900 and continues to be important today. Technology to maximize economic production from shallow-water fields can be adapted from onshore or deepwater technologies. Improvements in monitoring-system capabilities (and costs) are direct contributors to optimizing well and facilities operations. Several case studies illustrate the benefits of applying existing technology to increase production in mature operations. The first case study is of a gas/condensate field. Typical liquid-handling strategies were first applied to mitigate production decline, including converting the test separator to a low-pressure separator. Regular well testing is required for allocation and reservoir management. Previously, low-pressure wells were shut in during the well tests, resulting in production losses. Clamp-on sonar meters allow well testing every 2 months without shutting in production. Data from the sonar metering and other production-surveillance techniques have been used to optimize well cycling. The second case study describes implementation of through-tubing technology for sand control at a normally unmanned platform. The platform is located in shallow water with onerous sea states. Significant sand production began from an unconsolidated oil zone when the original gas well was converted to commingled production. This paper describes the selection and installation of through-tubing sand control and subsequent selection and installation of through-tubing gas lift. Critical success factors for well rejuvenation at this marginal field include managing marine issues and crane limits. The last case study discusses installation of a downhole electric heater in an offshore heavy-oil well. Heating heavy-oil reservoirs is uncommon offshore. This successful heater application uses a three-phase system with a cold section to protect the electrical submersible pump (ESP) used to lift the oil. Distributed-temperature sensing monitors temperature profiles in the well. Cable connections—power for the heater and the ESP—are critical for successful operation. JPT Recommended additional reading at OnePetro: www.onepetro.org. IPTC 16858 Downhole Electrical Heating for Heavy-Oil Enhanced Recovery: A Successful Application in Offshore Congo by F. Bottazzi, Eni, et al. OTC 23948 Full-Scale Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines by Nick Weppenaar, NOV Flexibles, et al. OTC 23968 Large-Diameter-Riser Laboratory Gas Lift Tests by G. Zabaras, Shell, et al.

Downhole Electrical Heating for Enhanced Heavy-Oil Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16858, ’Downhole Electrical Heating for Heavy-Oil Enhanced Recovery: A Successful Application Offshore Congo,’ by F. Bottazzi, C. Repetto, E. Tita, and G. Maugeri, Eni, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. Several enhanced-oil-recovery (EOR) techniques (thermal methods in particular) are currently available to achieve higher recovery factors in heavy-oil fields. However, some technologies, such as downhole electrical heating (DHEH), have been improved recently, allowing enhancement of production and therefore improvement of the recovery factor with relatively low investment cost in comparison with the high costs involved in the implementation of thermal technologies. To increase the production of a heavy-oil reservoir offshore Congo, a study of DHEH applications has been carried out with encouraging results. Introduction The Zatchi Marine field, operated by Eni Congo in partnership with Total Congo, is located approximately 25 km from the Congolese coast (Fig. 1). It is a multilayered sand reservoir with five oil-bearing levels (A through E). In particular, Level B is a 30-m-thick sand characterized by a large accumulation of heavy and highly viscous oil with the presence of both a bottom and a gas cap and very low reservoir pressure. Water depth ranges from 55 to 57 m, and there is an areal extension of approximately 34 km2. The development of the Zatchi B reservoir has always been an extreme challenge. Since the development of the field, six wells have been drilled and only three have been put into production, with sometimes unsatisfying results because of the severe problems of gas coning and cresting. An important improvement was achieved in 2008 with the drilling and completion of Well ZAM-408 ML, the first successful multilateral well ever drilled in West Africa and the first Technology Advancement of Multilaterals Level 6 technology applied in the Congo basin. Following this important achievement and the growing interest in the various EOR techniques and development scenarios, a dedicated study was conducted by Eni to evaluate and assess the most suitable integrated technology applicable to the Zatchi B reservoir. Reservoir simulations showed that among the different EOR techniques, thermal methods could enhance the recovery factor from this reservoir significantly. However, because the study is considering an offshore field (producing from a platform with very limited space and available power supply), and taking into account the heterogeneous reservoir environment, thermal methods were deemed to be too costly, with a high risk and a long-term implementation. Therefore, another technique was taken into consideration: cold production assisted by a DHEH system, which represents the edge between cold and hot production. DHEH allows production enhancement and thus improvement of recovery factor, with significantly lower investment costs when compared with those typically associated with the implementation of thermal technologies such as steam injection. This technology uses a three-phase system designed to provide a defined wattage according to the different applications and type of cables. The heater section is set downhole and is connected to the surface with a power cable. It generates heat to the near-wellbore region, decreasing viscosity and friction and, consequently, increasing oil mobility.

Deepwater Developments Driving Technip's Technology

Deepwater Developments Today’s deepwater projects are not just larger and more expensive than in years past. They are the most technically demanding projects the oil and gas industry has endeavored to undertake since stepping out from the continental shelf, and will require more new technology than ever to successfully execute. The extreme environments of deepwater fields are driving the complexity of these megaprojects to new heights, with shorter deadlines to help offset production declines. Among the companies capable of carrying out these record-setting field development projects is installation and subsea construction firm, Technip. The price tags of these projects have “exploded,” Pilenko said, because offshore oil and gas reservoirs are getting harder to find. So too is the challenge of safely producing those hydrocarbons and bringing them to the surface. “Today, we know how to drill at 3000-m depths,” he said. “But we are just learning how to produce it with qualified production systems.” Pilenko explained that the industry is not just pushing the frontiers of technology, but also geography. Offshore Africa, oil companies are proving how subsea fields can be developed with little to no onshore support infrastructure. One of the latest examples is the Moho Nord field, offshore Congo, where Technip will deploy some of its pipelaying and construction vessel fleet to install the entire subsea production system for operator Total. In terms of the scope of work, the project will be the largest subsea development that Technip has ever been awarded. The company will put into use many of its key assets to make and install the components of the subsea field that include 142 miles (230 km) of rigid pipeline, 14 miles (23 km) of flexible flowlines, and 31 miles (50 km) of umbilicals to deliver chemicals and power to the more than 50 subsea structures to be installed. Deepwater Facilities Under Construction Already the uncontested leader in spar development, having delivered 14 of the world’s 17 in operation, Technip is building three new spars simultaneously, including the world’s largest. Spars are deepwater floating facilities that rely on a cylindrical single-column design to achieve optimal stability for drilling and production in an offshore environment. The Technip-engineered Aasta Hansteen spar will be the biggest platform of its kind built, a distinction driven by the harsh environment of the North Sea and the fact that it is engineered for gas processing and storage. The hull will be 640 ft (195 m) from top to bottom and 167 ft (51 m) in diameter. The spar’s topside facilities will have a processing capacity of 812 MMcf/D of natural gas and a storage capacity of 160,000 bbl of gas condensate. The first spar to be installed offshore Norway, the Aasta Hansteen spar will operate at a water depth of 4,250 ft (1300 m) and is under construction in South Korea, with first production planned for the end of 2016.

Integrated approach to geomodelling and dynamic simulation in a complex mixed siliciclastic–carbonate reservoir, N'Kossa field, Offshore Congo

Abstract The Lower Sendji Carbonate (Albian age) of the N'Kossa field is a mixed siliciclastic–carbonate reservoir exhibiting very heterogeneous reservoir properties and the development of extensive vertical flow permeability barriers. The reservoir is a succession of interstratified dolomite, limestone, sandstone and shale lithologies of sabkha, tidal flat and lagoonal origin. Early, synsedimentary dolomite cements are extensively developed, particularly over local palaeohighs. Challenges to hydrocarbon production include: (1) the vertical variability of reservoir properties; (2) the presence of many, laterally extensive vertical flow barriers; and (3) variable connectivity between fault-bounded compartments. This complexity was underestimated at the appraisal stage, the initial development plan calling for a relatively simple scheme of pressure support to the critical reservoir fluid via injection into the gas cap and the water leg. This decision was supported by the identification of a single hydrocarbon column (>400 m thick) over the entire structure which suggested a lack of vertical compartmentalization. Recent studies, which include a geological synthesis of more than forty wells and a dynamic data synthesis to determine the production mechanism and identify key heterogeneities, show a lack of pressure support to the oil leg from both water and gas injector wells. Today, integration of static and dynamic data together with an improved geological understanding of the stratigraphic control on vertical flow barriers and mapping of high permeability sandstone layers is the key to identifying unswept zones of the field and future infill drilling targets.

Multiple Transverse Fracturing in Open Hole Enables Development of a Low-Permeability Reservoir

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119140, "Multiple Transverse Fracturing in Open Hole Allows Development of a Low-Permeability Reser voir in the Foukanda Field, Offshore Congo," by Alberto Casero, SPE, Loris Tealdi, SPE, Roberto Luis Ceccarelli, SPE, Antonio Ciuca, SPE, Giamberardino Pace, SPE, Eni; Brad Malone, SPE, Schlumberger; and Jim Athans, SPE, Packers Plus Energy Services, prepared for the 2009 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 19–21 January. The paper has not been peer reviewed. During the past decade, multiple transverse fracturing in horizontal wells has been applied successfully in onshore low-permeability reservoirs. The reasons for the success of this technique are related to the effectiveness of hydraulic fracturing for production enhancement and to the relatively low cost of pumping services onshore. Offshore, high direct and indirect costs and the risks associated with operations have limited the use of this technology. This study documents the successful effort of taking these techniques offshore. Transverse fracturing with multistage completion—with properly engineered design of the well trajectory—can provide economic success of field development of low-permeability reservoirs. Introduction The Foukanda marine field is 20 km north of the Kitina platform and 52 km west of the city of Pointe Noire, Congo. Average water depth is 100 m. The field was discovered in 1998, with initial production in June 2001. That year, one well was drilled in the D reservoir, but it had very poor reservoir characteristics, and this level was abandoned. The well was recompleted in the shallower B4 reservoir. The low-permeability D reservoir (less than 10 md) was abandoned. Successful fracture treatments in the Kitina field in May 2007 proved the possibility of obtaining economical rates from a marginal reservoir. It was decided to test the multistage hydraulic-fracturing technology on the previously abandoned D reservoir in the Foukanda field. Synergy from early cooperation among drilling, reservoir, and production-enhancement engineers proved key for the operation. An optimum process path was followed: reservoir assessment, selecting optimum fracture(s) configuration, providing input for the drilling plan, selecting the proper completion to allow optimum fracture(s) placement, and, finally, plan execution. The original plan on Foukanda was to drill a new vertical or deviated well with one or two fractures. Fracturing engineers suggested changing this plan and drilling a horizontal well and completing it with multiple transverse fractures. The deviated well was discarded because of complex fracture-growing issues, which, in the best case, could have transverse fractures that are not properly spaced, resulting in fracture/production interference. The advantage of having transverse fractures in a horizontal well is the possibility of proper spacing and deciding the optimum number of fractures that are required.

西アフリカ大水深における探鉱成果に基づく考察―ガボン・アンゴラのタービダイト砂岩を探る―

Deep water offshore West Africa is the most prolific petroleum exploration and production area in the last decade. “Golden Triangle” consists of US Gulf of Mexico, Brazil Campos and West Africa and is well known as three world class most prolific and promising deep water E&P areas. Especially, deep offshore Niger delta and Congo fan are the most prolific amongst them. 3D seismic data associated with advanced interpretation and visualization technique supported by recent powerful computer capability as well as sequence stratigraphy concept have contributed very efficiently to deep water success in West Africa. An approach utilizing seismic multi-attribute is the essential element for reservoir delineation and risk minimization because turbidite sand is significantly heterogeneous and thus development well spacing/positioning should be optimized by integrated reservoir study. A seismic-well log study example in deep water offshore Gabon is briefly introduced in this paper.

Rates of deformation of an extensional growth fault/raft system (offshore Congo, West African margin) from combined accommodation measurements and 3‐D restoration

AbstractsThe aim of this paper is to quantify the evolution in time and space of the accommodation (space available for sedimentation) in the case of a growth fault structure resulting from gravity‐induced extension comprising a listric fault/raft system located along the West African margin. To achieve this, use was made of an original approach combining two complementary techniques (accommodation variation measurements and 3‐D restoration) in order to quantify vertical and horizontal displacement related to deformation, using a data set made up of a 3‐D seismic survey and well logs. We applied sequence stratigraphic principles to (i) define a detailed stratigraphic framework for the Albo‐Cenomanian and (ii) measure subsidence rates from accommodation variations. 3‐D restoration was used to (iii) reconstruct the evolution of the 3‐D geometry of the fault system. The rates of horizontal displacement of structural units were measured and linked to successive stages in the growth of the fault system.Subsidence of the structural units exhibits three scales of variation: (1) long‐term variation (10 Ma) of c. 80 m Ma−1 for a total subsidence of about 1400 m, compatible with the general subsidence of a passive margin, and (2) short‐term variations (1–5 Ma) corresponding to two periods of rapid subsidence (about 150–250 m Ma−1) alternating with periods of moderate subsidence rate (around 30 m Ma−1). These variations are linked to the development of the fault system during the Albian (with downbuilding of the raft and development of the initial basin located in between). During the Cenomanian, the development of the graben located between the lower raft and the initial basin did not seem to affect the vertical displacements. (3) High‐frequency variations (at the scale of genetic unit sets) range between −50 and 250 m for periods of 0.2–2 Ma. Accommodation variations governed these cycles of progradation/retrogradation rather than sediment flux variations. In addition, the nine wells display a highly consistent pattern of variation in accommodation. This suggests that the genetic unit sets were controlled at a larger scale than the studied system (larger than 20 km in wavelength), for example, by eustatic variations. Translation rates are between 3 and 30 times higher than subsidence rates. Therefore, in terms of amplitude, the main parameter controlling the space available for sedimentation is the structural development of the fault system, that is to say, the seaward translation of the raft units, itself resulting from a regional gravity‐driven extension.

Sendji Formation reservoir delineation based on 2-D and 3-D inversion, Yombo Field, offshore Congo

Seven fields with prolific Sendji Formation production have been discovered offshore Congo. These fields have ultimate recoveries of 100 million b/o or greater. Only the shallow waters (less than 200 m) of the play have been adequately explored. The inability to predict the amount of economically recoverable oil after initial discovery and delineation is a major production challenge. The Sendji Reservoir is a complex sequence of limestones, dolomites, and sandstones deposited as several distinct facies. These facies vary both laterally and vertically, and have vastly different reservoir characteristics. Predicting the configuration of these facies is the key to predicting reservoir performance and calculating the amount of oil that is economically recoverable. Predicting intra-Sendji facies distribution is a significant challenge to optimizing development drilling.

ABSTRACT: Rates of Deformation of a Growth Fault/Raft System (Offshore Congo, West African Margin) from Combined Accommodation Measurements and 3-D Restoration

ABSTRACT: Rates of Deformation of a Growth Fault/Raft System (Offshore Congo, West African Margin) from Combined Accommodation Measurements and 3-D Restoration

Structure et évolution récente de l’éventail turbiditique du Zaïre : premiers résultats scientifiques des missions d’exploration Zaïango1 & 2 (marge Congo–Angola)

Two scientific submarine exploration cruises were realised in 1998 offshore Congo and Angola within the ZaïAngo project. The main goal of the project is the study of the present and recent Zaire submarine fan. The survey followed the present channel down to its distal end, 760 km from the river mouth at a water depth of 4 800 m. Preliminary results indicate that it feeds a distal lobe complex. Only one turbiditic channel is active at one time. The channels are highly meandering in their upper course. More than 80 palaeochannels have been identified both south and north of the present channel. The estimated area of the Zaire deep-sea fan is close to those of the Amazon fan. Nous présentons ici les résultats préliminaires de deux premières campagnes d’exploration réalisées au large du Congo et de l’Angola dans le cadre du projet ZaïAngo, dont l’objectif central est l’étude du système turbiditique actuel et récent du Zaïre. Nous avons pu reconnaître le tracé du chenal actuel jusqu’à son extrémité (à 760 km de l'embouchure du fleuve), où il débouche, par 4 800 m de profondeur d’eau, sur un complexe de lobes distaux emboîtés. Le chenal actuel est unique et très méandriforme dans son cours supérieur. Il est surcreusé sur tout le long de son cours. Les levées sont caractérisées par l'omniprésence de dunes sédimentaires géantes. Plus de 80 paléochenaux ont été identifiés, tant au nord qu’au sud du chenal actuel. On estime que la surface de l'Éventail du Zaïre doit être proche de celle de l'Amazone.

Nearby finds brighten outlook

Equatorial Guinea and Namibia are situated on the northern and southern ends of the West African deepwater play fairway. Between them lie the prolific petroleum provinces of offshore Gabon, Cabinda, Congo, and northern Angola.

Abstract: Geologic Controls on the Gas Hydrate Distribution, Offshore Congo

Abstract: Geologic Controls on the Gas Hydrate Distribution, Offshore Congo

Abstract: Petroleum Geology of the Lombo East and Essungo Oil Fields, Block 2, Offshore Congo Basin, Angola

Abstract: Petroleum Geology of the Lombo East and Essungo Oil Fields, Block 2, Offshore Congo Basin, Angola

Abstract: Integrated Deterministic Approach in Reservoir Simulation: Example of the Albian Nkossa Reservoir - Offshore Congo  

Abstract: Integrated Deterministic Approach in Reservoir Simulation: Example of the Albian Nkossa Reservoir - Offshore Congo  

A statistical methodology for deriving reservoir properties from seismic data

The use of seismic data to better constrain the reservoir model between wells has become an important goal for seismic interpretation. We propose a methodology for deriving soft geologic information from seismic data and discuss its application through a case study in offshore Congo. The methodology combines seismic facies analysis and statistical calibration techniques applied to seismic attributes characterizing the traces at the reservoir level. We built statistical relationships between seismic attributes and reservoir properties from a calibration population consisting of wells and their adjacent traces. The correlation studies are based on the canonical correlation analysis technique, while the statistical model comes from a multivariate regression between the canonical seismic variables and the reservoir properties, whenever they are predictable. In the case study, we predicted estimates and associated uncertainties on the lithofacies thicknesses cumulated over the reservoir interval from the seismic information. We carried out a seismic facies identification and compared the geological prediction results in the cases of a calibration on the whole data set and a calibration done independently on the traces (and wells) related to each seismic facies. The later approach produces a significant improvement in the geological estimation from the seismic information, mainly because the large scale geological variations (and associated seismic ones) over the field can be accounted for.