Carlos H.L. Bruhn

Campos Basin: Reservoir Characterization and Management - Historical Overview and Future Challenges

The first oil discovery in the Campos Basin dates from 1974, when the ninth well drilled found Albian carbonate reservoirs (Garoupa Field) under a water depth of 120 m. Oil production started on August 13, 1977, from the Enchova Field, which produced to a semi submersible platform moored at a water depth of 124 m. This was the beginning of a successful history that led Petrobras to become a world leader company in petroleum exploration and production in deep and ultra-deep waters. Forty-one oilfields were found between 50 and 140 km off the Brazilian coast (under water depths between 80 and 2,400 m), which produce from a variety of reservoirs, including Neocomian fractured basalts, Barremian coquinas, early Albian calcarenites, and (mostly) late Albian to early Miocene siliciclastic turbidites. These reservoirs were responsible for an average oil production of 1.2 million bpd in the year 2002 (83% of the total Brazilian production), and they are expected to be producing 1.6 million bopd by the end of 2005. The cumulative oil production from the Campos Basin comprises 3.9 billion bbl, and the current proven oil reserves are 8.5 billion bbl (89% of total Brazilian reserves). Deep and ultra-deep water giant fields started to be discovered only in 1984. There was a succession of large discoveries, including Albacora, Marlim, Albacora Leste, Marlim Sul, Barracuda, Caratinga, Roncador and, more recently, Jubarte and Cachalote. The development of these fields has continuously provided new challenges for the reservoir characterization and management in the Campos Basin. These fields are developed with fewer, horizontal and high angle wells, drilled into poorly consolidated reservoirs. The extensive use of 3D seismic as a reservoir characterization tool has optimized well location and allowed the reduction of geological risks. Integration of high-resolution stratigraphic analysis with 3D seismic inversion, geostatistic (stochastic) simulation of reservoir properties constrained by seismic, well log and core data, 3D visualization, and voxel-based automatic interpretation has guided the positioning of horizontal wells through thin (<10-15 m) reservoirs. Additionally, 3D visualization techniques have provided a new environment for teamwork, where seismic, well log, and core data are interpreted and added to detailed 3D geological models and, subsequently, to robust reservoir simulation models. The deepwater subsea wells must be designed to allow high production rates (typically >10,000-15,000 bopd), with lifetime completions to avoid costly interventions. In order to assure high productivity, pressure maintenance must be efficient; if water injection is planned, the hydraulic connectivity between injector and producer wells must be guaranteed by high-quality 3D seismic, well log correlation, and observed pressure profiles. Detailed studies have been made in order to define the distribution and number of wells, since the number of wells strongly affects the net present value of deepwater projects. Wells with expected oil recovery of less than 10-15 million bbl are not drilled in the beginning of the projects, and remain as future opportunities to increase oil production and recovery. Some of the new technologies devised for the characterization and development of the deepwater oilfields from the Campos Basin include reservoir imaging with prestack, depth-migrated seismic, 4D seismic, real-time well steering and updating of geological/reservoir models, extended reach wells, selective completion in gravel-packed wells, isolation inside horizontal, gravel-packed wells, intelligent completion, subsea oil-water separation, re-injection of produced water, scale prevention and treatment, and improved recovery techniques for heavy and/or viscous oil. Introduction Campos Basin is located in southeastern Brazil, mostly offshore of the states of Rio de Janeiro and Espírito Santo, occupying an area of 115,000 km (Fig. 1). The basin has a small (500 km) onshore portion, where the first exploratory well was drilled in 1959; this well records a 1,690 m-thick, very sand-rich Tertiary succession, Neocomian basalts, and the Precambrian metamorphic basement. Exploration in the offshore Campos Basin started in 1968, with the acquisition of 2D seismic data. The first offshore well was drilled in 1971. The first oil discovery dates from 1974, when the ninth well drilled found Albian carbonate reservoirs (Garoupa Field) at a water depth of 120 m. Oil production started on August 13, OTC 15220 Campos Basin: Reservoir Characterization and Management – Historical Overview and Future Challenges Carlos H.L. Bruhn, José Adilson T. Gomes, Cesar Del Lucchese Jr., and Paulo R.S. Johann / Petrobras E&P, Rio de Janeiro, Brazil

High-resolution Stratigraphy and Sedimentary Evolution of Coarse-Grained Canyon-Filling Turbidites From the Upper Cretaceous Transgressive Megasequence, Campos Basin, Offshore Brazil

ABSTRACT Coniacian to Lower Maastrichtian coarse-grained turbidites fill intra-slope, fault-controlled canyons in the Campos Basin, off-shore Brazil. They form part of an Upper Albian to Lower Paleocene transgressive succession characterized by onlapping, deepening-upward sedimentation throughout the eastern Brazilian margin. In the Carapeba and Pargo (CRP-PG) oil fields the turbidites consist mainly (> 95%) of graded beds without any other sedimentary structures. Individual beds are up to 12 m thick and are composed of small pebble(< 2 cm) to granule-rich sandstones, and medium to very coarse sandstones. The finer-grained portions of these graded beds show better sorting and higher porosity, and these characteristics can be recognized in density logs. Use of 92 density logs calibrated w th 13 cores permitted the mapping of 198 coarse-grained turbidites in the CRP-PG turbidite system. The turbidites form eight thinning- and fining-upward facies successions, some bounded by regional unconformities or local erosion surfaces. The successions are 27-140 m thick and contain 7-58 turbidites. Their durations are estimated to be between 0.4-0.9 m.y. They form 1-12 km wide, tabular or linguoid sandstone bodies in which the younger or more distal turbidites become finer-grained, thinner-bedded, and more discontinuous upsection and downcanyon. The successions are stacked in an overall retrogradatioual pattern for at least 20 km, recording the backfilling of the CRP-PG canyon. Turbidites in the CRP-PG area were probably deposited during falls of relative sea level that punctuated the overall transgressive setting of the late Cretaceous and early Tertiary. There is a mismatch between the number of successions (eight) and the number of time-equivalent third-order fluctuations of relative sea level (four and part of a fifth; Haq et al 1988), suggesting that eustatic sea level fluctuation was not the dominant control on most of the successions. Cross sections and isopach maps of the successions do not suggest internal channeling, and a channel-fill origin for the fining- and thinning-upward successions seems unlikely. We therefore suggest that episodic tectonic reactivation in the uplifted Precambrian source area, and faulted basin margin, led to relatively abr pt increases in the volume of sediment supplied to the head of the canyon across a narrow shelf. Steady denudation and decreasing supply of sediment led to formation of the fining- and thinning-upward successions.

Marlim Complex Development: A Reservoir Engineering Overview

Since the discovery of the Garoupa Field in the Campos Basin, Rio de Janeiro, Brazil, in 1973, Petrobras has been moving to deeper waters. Subsea engineering and well technologies have been developed and applied to overcome the environmental restrictions. Today more than 50% of Brazil’s oil production comes from fields located offshore in water depths over 1,000 m. In this scenario, the Marlim Complex – which comprises the Marlim, Marlim Sul and Marlim Leste fields – plays an important role. Discovered in 1985, the Marlim Field started production in 1991, with a pilot system comprising 7 wells connected to a semi-submersible unit moored in a water depth of 600 m. Currently, the field production is about 85,000 m/d (535,000 bpd), with 60 producers and 32 water injectors connected to 7 floating production units. As with other Campos Basin turbidites, the Oligocene/Miocene reservoir of Marlim Field presents 3 outstanding characteristics: predictability, from seismic data and geological modeling, excellent petrophysical properties and good hydraulic connectivity. The extensive use of 3D seismics as a reservoir characterization tool allows the reduction of risks and the optimization of well locations. Additionally, 3D visualization techniques provide a new environment for teamwork, where seismic data is interpreted and input into detailed reservoir simulation models. Among the deep water well technologies employed to develop the Marlim Complex it is worth mention: slender wells, high rate well design, horizontal and high angle wells in unconsolidated sands, efficient low cost sand control mechanisms, selective frac-pack with isolation between zones, pressure downhole gauges (PDG’s), new techniques for the connection of flowlines and X-mas trees, subsea multiphase pumping and special techniques to remove paraffin in the flowlines. However, new developments are required, such as extended reach wells, selective completion in gravel-packed wells, isolation inside horizontal gravel-packed wells with External Casing Packers (ECP’s), smart completion and improved recovery techniques for viscous oil. Much has been learned during the planning and development of the Marlim Field and this knowledge is currently being applied in the development of Marlim Sul and Marlim Leste fields. Some important points must always be observed: a) the development plans must be defined by using optimization techniques considering the geological risks; b) the number of wells of the initial development plan must be defined through a detailed optimization study, considering economic indicators, oil recovery and risks; c) the wells must be designed to allow high production rates, with “rest of life” completions, as simple as possible; d) the sand control mechanisms must be simple, efficient and low cost, e) the seismic resolution or the production data analysis must be of sufficient quality to guarantee that there will be good hydraulic connectivity between the producers and the corresponding injectors; f) the pipelines and risers must be designed to avoid bottle-necks or conditions for deposition of wax or hydrates and g) the reservoir management and particularly the water injection system management must be made with an integrated teamwork approach. In this paper we present some aspects of the reservoir engineering and of the development plan of the Marlim Field and briefly discuss how this experience is being used in the development of the neighboring Marlim Sul and Marlim Leste fields. Introduction The Marlim Complex comprises 3 giant deepwater oil fields – Marlim, Marlim Sul and Marlim Leste – located in the Campos Basin, 110 km offshore Rio de Janeiro, Brazil (Fig. 1). Besides the geographic location, these fields have other similarities: the main reservoirs are turbidites of Oligocene / Miocene age; 3D seismic data allows accurate prediction of the reservoir occurrence; rock characteristics are excellent; relative permeabilities are favorable to water injection and well productivities are very high. SPE 69438 Marlim Complex Development: A Reservoir Engineering Overview Antonio C. Capeleiro Pinto, SPE, Solange S. Guedes, SPE, Carlos H. L. Bruhn, J. Adilson T. Gomes, SPE, Andrea N. de Sá, SPE, and J. R. Fagundes Netto, PETROBRAS S. A. 2 PINTO, A. C. C., GUEDES, S. S., BRUHN, C. H. L., GOMES, J. A. T., N. DE SÁ, A. AND FAGUNDES NETTO, J. R. SPE 69438 The Marlim Field was discovered in 1985 by an exploratory well drilled in a water depth of 850 m, which found 70 m of the Oligocene / Miocene reservoir saturated with 20 API oil. Four additional appraisal wells delimited the accumulation, and the STOIIP is estimated at 1,020 million STD m (6,416 million STB). The field area is 165 km and the water depth range is 600 1100 m. The oil API changes from 18 and 21 in the main field area, the oil viscosity in the reservoir is between 4 and 8 cp and the saturation pressure is 22 kgf/cm below the original pressure of 287 kgf/cm. Rock characteristics are excellent. To investigate well performance, reservoir connectivity, oil flow in low temperature pipelines, and also to test well completion and subsea technology, a production pilot was implemented in 1991. Seven subsea wells located in the northern field area were connected to a semi-submersible unit, Petrobras-20 (P-20), moored outside the field area in order to reduce interference with development. All of the seven wells were perforated in the uppermost sand of the reservoir. The production pilot supplied important information which guided subsequent phases of the field development: a) RFT’s in new wells showed that all sands depleted at almost the same rate, showing that the reservoir has good vertical communication; b) subsequent wells drilled in the southern part of the field also depleted, proving reservoir continuity; c) material balance could be used to calibrate the reservoir volume calculated from geological mapping; d) for the longer flowlines, paraffin deposition reduced well potential, requiring remedial actions. In 1994 the first production unit of the definitive system, a semi-submersible unit named P-18 started operation, moored in a water depth of 910 m. This unit was designed considering oil processing capacity of 16,000 m/d (100,000 bpd) and water injection capacity of 24,000 m/d (150,000 bpd). Five additional units were installed in the field, and the present situation is shown in Table 1. Currently, Marlim Field production is around 85,000 m/d (540,000 bpd), the water injection is 101,000 m/d (640,000 bpd) and the recovery factor to date is 7.2%. The water production is 3,300 m/d (BSW = 3.7%) and GOR is equal to the initial solubility ratio, 80 m/m. A total of 92 wells are operating, with 60 producers and 32 water injectors. The field development will be completed by the end of the year 2001, when the production peak will be reached. The Marlim Sul Field is located directly south of Marlim, comprising an area of more than 600 km, under water depths ranging from 1,000 to 2,600 m. The field was discovered in 1987 by an exploratory well drilled in 1250 of water depth which found 40 m of the Oligocene / Miocene age reservoir saturated with 25 API oil. Subsequently, 12 appraisal wells completed the field delimitation. The field STOIIP is estimated at 1,400 million STD m (8,806 million STB), 90% in Oligocene / Miocene reservoirs and 10% in Eocene reservoirs. Oil API reaches 28 at the northern part of the field and decreases as water depth increases. As for the neighboring Marlim Field, reservoir characteristics are excellent. However, stratigraphy is more complex, and predicting and identifying the reservoir compartments is an important and difficult task. To date 19 reservoir blocks have been identified and mapped in Marlim Sul, but hydraulic connectivity between them is not completely understood. To investigate the reservoir performance 3 production pilots were implemented in the field: (1) In 1994 Well MRL-4, drilled in 1,027 m of water depth, started production to the platform P-20 in Marlim Field, flowing through 20 km of subsea pipeline. Currently it produces to P-26 through a 7 km flowline with a rate of about 1,800 m/d. The material balance indicated that this well produced from a 170 million m STOIIP reservoir. In 1999 an injector in this block was connected to P-26, for pressure maintenance; (2) In 1997 the subsea completion world-record well MLS-3B, drilled in a water depth of 1709 m, was connected to a Floating Production Storage and Offloading (FPSO) through 3 km of subsea flowline. This well produced 16.5 API oil during almost one year, having reached a production peak of 1,500 m/d. New subsea technology developed by the Petrobras Technological Program on UltraDeep Water Explotation Systems (PROCAP) were successfully tested in this well. Besides, information regarding low temperature oil flow in pipes and gas-lift performance were obtained and allowed the calibration of the multiphase flow correlations. (3) Finally, in 1999 Well MLS-2, drilled in a water depth of 1,230 m was connected to the aforementioned FPSO, now repositioned to a shallower water depth. This well produces 2,500 m/d of 22 API oil through a 3.5 km flowline. Again, production has allowed for material balance and the calculation of the oil volume connected to the well. The information obtained in these pilot production systems guided the development plan of the Marlim Sul field. The first production unit, the semi-submersible P-40, is schedule to start production in July, 2001, and 17 of its 28 development wells have already been drilled. New seismic data, acquired in the beginning of the year 2000, is helping to define the reservoir structure and internal stratigraphy and consolidate the development plan for the whole field. The Marlim Leste Field was discovered in 1987 by an exploratory well drilled in a water depth of 1230 m. The well found 70 m of the Oligocene / Miocene reservoir saturated with 19.5 API oi

Adaptive visualization of deepwater turbidite systems in Campos Basin using 3-D seismic

Oil accumulations in the deepwater Campos Basin offshore Brazil are found in Oligocene/Miocene sand-rich turbidites of contrasting architectural types. Reservoirs are sand lobes with thickness of 50 m, width of 1–5 km wide, and length of 2–10 km that display compensation stacking patterns. The reservoirs show bright reflections in a single amplitude trough corresponding to a relative decrease in impedance. In the study area, turbidite successions have high structural dips and complex spatial distribution. Their individual geometries are very difficult to map using conventional 3-D data.

Reservoir Architecture of Deep-Lacustrine Sandstones from the Early Cretaceous Recôncavo Rift Basin, Brazil

Synrift, lacustrine sedimentation took place along the entire eastern Brazilian margin in response to the Neocomian breakup of Gondwana. In the Reconcavo basin, a deep lake was developed and filled mainly by a thick (>2000 m) succession of dark-colored, organic-rich mudstones and sandstones, and by subordinate, oncolite- and Ostracod-rich carbonates. In the Fazenda Balsamo oil field, near the northeastern border fault margin of Reconcavo basin, deep-lacustrine reservoirs comprise a succession up to 424 m thick composed mainly of laminated (lower section) and massive (upper section), medium- to fine-grained sandstones. Their porosities and permeabilities typically range from 14 to 23%, and 100 to 500 md, respectively. The sandy reservoirs and interbedded source-rock mudstones comprise eight transgressive successions (mostly 20-120 m thick) bounded by basin-wide, mudstone marker beds. The average duration (about 83,000 yr) of each succession suggests that climatically driven lake level fluctuations may have modulated the cyclic, deep-lacustrine sedimentation in the study area; however, the interaction of changes in lake level with tectonic activity defined the dominant type of reservoir facies and the geometry and position of sand bodies. Laminated sandstones form sandstone bodies that are 600-1200 m wide, 1.5-4.5 km long, and up to 46 m thick, which fill northeast-oriented, fault-bounded troughs. These rocks probably were deposited by long-duration, sand-rich density underflows preferentially developed during rising lake level or highstands. These rocks may reflect an increasingly humid climate and more powerful and sediment-loaded influent streams. The more intense fault activity during the deposition of the lower reservoir section would have axially focused density underflows coming from the northeastern end of the basin. Massive sandstones comprise turbidite channel-fills that are 100-800 m wide, more than 2 km long, and up to 38 m thick. Fault activity diminished during the deposition of the upper reservoir section, allowing the cutting and filling of northwest-oriented channels by turbidity currents derived from the nearby border fault margin, preferentially during falling lake level or lowstands. Despite the local erosion associated with some turbidite channels, no unconformity or widespread erosion surface can be recognized within the studied succession. The relatively rapid and continuous tectonic subsidence along the eastern border fault margin of the Reconcavo basin provided virtually unlimited accommodation space for the aggradational stacking of climatically controlled, deepening-upward successions.

A multi-scale approach to improve reservoir characterization and forecasting: the Albacora Field (deep-water offshore Brazil) study

The Upper Albian Namorado Sandstone is one of the reservoirs of the Albacora Field, located in the Campos Basin, deep-water offshore Brazil. It is a sand-rich turbidite system where the most important controls on permeability are calcite cementation, thin beds of non-reservoir lithologies and some north–south trending faults. A major multidisciplinary reservoir characterization project was conducted to improve the reservoir description using all available data. In this paper, we focus on how the effect of rock heterogeneities were represented in the fluid flow model and on the performance obtained from this model. The basic idea was to define a hierarchical model of facies established on the basis of three main work scales: porous systems (thin sections and core sample scale); composite facies (whole core and log scale); and seismic facies (interwell to field scale). An up-scaling technique, based on the geopseudo concept, was used to generate the effective petrophysical properties for the fluid-flow simulation model. A Markov–Bayes geostatistical simulation method was applied in facies stochastic modelling. The sophisticated model that was built allowed very fast history matching.

Deep-Water Turbidite Systems Visualization In the Campos Basin, Brazil

Summary 3-D seismic visualization using stratigraphic and structural concepts combined with several transparency levels of volume data is essential to isolate amalgamated turbidite systems in deep-water Campos Basin, Brazil. An adaptive visualization method has been developed for those sedimentary occurrences with similar seismic attributes which can not be mapped by either conventional 3-D sections tracking methods, or modern 3-D surface or volume visualization techniques based only on physical opacity approaches. A condensed section seismic event was used as a key stratigraphic surface to generate major horizon slices and then we were able to reconstruct turbidite subsystems. This was accomplished by using well-known models, several adapted stratal surfaces, and different levels of seismic impedance transparency. These techniques isolated six turbidite bodies from a deepwater area of the basin, and identified oil-saturated, water-saturated and untested sands in a 9 km-long turbidite system. Images were correlated with the results of a vertical well.

Sublacustrine Fan Reservoirs of Riacho da Barra Field, Reconcavo Rift Basin, Brazil: ABSTRACT

The producing sandstone of Riacho da Barra field represents the middle and distal portions of uplap sublacustrine gravitational fans, deposited in a northeast-southwest elongate graben developed during the Early Cretaceous on the northeastern part of the Reconcavo rift basin, Brazil. Since the earliest stages of exploitation of the field, geologists and engineers have worked together to describe the reservoirs. A geologic and hydrologic model for the Riacho da Barra field was proposed, with emphasis on the lateral continuity of the reservoirs, which was mainly controlled by pressure-gradient correlations. This model was created to guide not only the development of the field, but also to define the possible use of waterflooding as a secondary recovery method. Two main reservoir sets were identified. The first group corresponds to medium-grained, well-sorted, massive sandstones, with centimetric conglomerate levels, deposited in channels in the middle of gravitational fans. This group represents the best reservoirs, with an average porosity of 16% and average permeability of 100 md, but restricted lateral continuity. Major trends of channel deposits are the most favorable directions for waterflooding. The second group includes a cyclic sequence of coarse-grained massive sandstones and medium-grained parallel-stratified sandstones, deposited as lobes of middle and distal fans. These sandstones have a wider distribution and contain 85% of the original oil in place of the field (50 million stock tank bbl). However, they have poorer reservoir quality, with average porosity of 12% and average permeability of 20 md. These characteristics are due to the significantly large thickness of poorly sorted parallel-stratified sandstones and also to the thin sandstone beds interlayered with shales, which show high contents of calcite cement. End_of_Article - Last_Page 241------------