Albacora Field Research Articles

Integration of seismic stratigraphy and cyclostratigraphy for high resolution chronostratigraphic correlation: The Albacora Field, Campos Basin, Brazil

High-resolution chronostratigraphy is fundamental for a refined interpretation of the evolution of sedimentary basins and, consequently, for generating more accurate geological models, which are essential for oil and gas exploration. This study provided an innovative integration of seismic reflectors interpretation, a biostratigraphic framework and 405-kyr astronomically-tuned age models from three wells, arranged in a dip section comprising Miocene deposits in the slope break of the Albacora Field, Campos Basin, Brazil. We (i) to provide a high-resolution, 2D astrochronologic model from the combination of three astronomical timescales (ATSs) – comprising a timespan of ∼3 Myr for the dip section; (ii) infer that the studied section comprises the middle Miocene deposits and records the Miocene Optimum Climate, and the significant eustatic falls that delimit this event; and (iii) provide refined age estimates for the seismic reflectors near the biozones.

Shallow Water: The Next Frontier for Deepwater Rigs, or Just a Passing Fad?

Petrobras, one of the world’s top offshore operators, has shared new information about how it used an ultradeepwater rig in a place where it was never intended to work—in shallow water. What makes its recent subsea campaign novel is that the Brazilian national oil company avoided mooring the rig and instead relied on dynamic positioning (DP). Two key pieces of technology made this possible. The first is called a blowout preventer (BOP)-tethering system which sits on the seabed and absorbs much of the load being placed onto the wellhead structure. The second is a digital twin software that determines the safety of the rig’s position during drilling. Petrobras is not the first to accomplish such a feat in depths less than 2,000 ft. But it is among the few to recount its learnings in multiple technical papers as it did at the recent Offshore Technology Conference (OTC) in Houston. The fresh insights surrounding the Petrobras projects stem from an initial well drilled and completed 2 years ago with a sixth-generation drillship, the Norbe VIII, owned by Brazilian contractor Ocyan. The new well is in the Albacora field within the Campos Basin and was the first of several planned to be drilled or plugged and abandoned by Petrobras in DP-only mode. Over a 16-day period in May 2020, the Norbe VIII worked in water depths of about 1,475 ft where it successfully tapped into a pre-salt oil reservoir with a total depth of more than 16,000 ft. For both firms, the project in the Campos Basin marked a first. Never before had they used a rig in DP-only mode at such shallow depths, which amounted to about 15% of the rig’s maximum depth rating. Following the first well, Petrobras drilled at least one more in June 2021 in DP-only mode. Notably, Petrobras was in the midst of selling off the Albacora field during its experimentation with DP-only shallow-water drilling. The mature asset was discovered by the state-run operator in 1984 about 75 miles from the coast and has been producing from post-salt reservoirs for the past 35 years. But earlier this year, the company said it was hoping to fetch a higher price based on better-than-expected reservoir tests from the deeper pre-salt target it drilled in May 2020.

Image-ray concept as the key to 20 years of success of time-to-depth conversion in Petrobras

The evolution and characteristics of the time-to-depth conversion method of time-migrated data that has been used successfully at Petrobras for the last 20 years is described. Such methodology is primarily based on the image-ray concept, but also integrates other imaging techniques such as multiple-stacking Kirchhoff migration and wavefront construction. To illustrate the methodology's usage as well as some problems that were overcome, two examples are provided: one at Roncador field and the other at Albacora field.

Sequence stratigraphy of the Eocene turbidite reservoirs in Albacora field, Campos Basin, offshore Brazil

This article describes a 250-m (820-ft)-thick upper Eocene deep-water clastic succession. This succession is divided into two reservoir zones: the lower sandstone zone (LSZ) and the upper sandstone zone, separated by a package of pelitic rocks with variable thickness on the order of tens of meters. The application of sequence-stratigraphic methodology allowed the subdivision of this stratigraphic section into third-order systems tracts. The LSZ is characterized by blocky and fining-upward beds on well logs, and includes interbedded shale layers of as much as 10 m (33 ft) thick. This zone reaches a maximum thickness of 150 m (492 ft) and fills a trough at least 4 km (2 mi) wide, underlain by an erosional surface. The lower part of this zone consists of coarse- to medium-grained sandstones with good vertical pressure communication. We interpret this unit as vertically and laterally amalgamated channel-fill deposits of high-density turbidity flows accumulated during late forced regression. The sandstones in the upper part of this trough are dominantly medium to fine grained and display an overall fining-upward trend. We interpret them as laterally amalgamated channel-fill deposits of lower density turbidity flows, relative to the ones in the lower part of the LSZ, accumulated during lowstand to early transgression. The pelitic rocks that separate the two sandstone zones display variable thickness, from 35 to more than 100 m (115–328 ft), indistinct seismic facies, and no internal markers on well logs, and consist of muddy diamictites with contorted shale rip-up clasts. This section is interpreted as cohesive debris flows and/or mass-transported slumps accumulated during late transgression. The upper sandstone zone displays a weakly defined blocky well-log signature, where the proportion of sand is higher than 80%, and a jagged well-log signature, where the sand proportion is lower than 60%. The high proportions of sand are associated with a channelized geometry that is well delineated on seismic amplitude maps. Several depositional elements are identified within this zone, including leveed channels, crevasse channels, and splays associated with turbidity flows. This package is interpreted as the product of increased terrigenous sediment supply during highstand normal regression.

Techbits: Workshop Covers Subsea Processing Issues

Techbits An SPE Applied Technology Workshop (ATW) on subsea processing recently took place in Stresa, Italy. The workshop was divided into sessions covering concept development, subsea boosting, subsea compression, subsea power, subsea separation, and operational experience. Each session included topic presentations, question-and-answer sessions, and mini-workshops allowing participants to interact, learn, and share from one another. Subsea processing is allowing increased recovery, lower capital and operating expenses, and health, safety, and environmental (HSE) benefits. Subsea processing success stories are increasing in number and during the workshop participants heard that: Petrobras has extensive experience from subsea electric submersible pumps (ESPs) and has recently applied subsea mudline multiphase pumping (MMP) pumps at the Barracuda field, subsea raw water injection pumps at the Albacora field, horizontal mudline ESP skid at the Espardarte field, and a subsea gas/liquid separation system and an oil/water separation system at the Marlim field. At the Vincent field, Woodside has applied a subsea MPP system, including two off multiphase pumps. The processing system has given accelerated production and increased the availability of topside facilities and will extend the production life of wells. Pazflor’s subsea separation units (SSUs) have been in operation and operator Total considers the project a success for subsea processing. SSUs make topsides facilities easier to operate. Statoil and Shell are confident that the technology can be deployed at Ormen Lange. Rigorous qualification testing, access to good test facilities, and a stepwise development of technologies are important factors to succeed with the implementation of new subsea processing technologies and to mitigate risk. Communication of success stories and a correct allocation of risk for subsea processing technologies are critical to the selection of subsea processing solutions by decision makers. Concrete new subsea separation projects and business cases are relatively few and there seems to be less confidence and some confusion about the maturity of separation technologies. Several suggestions for improvement were discussed during the workshop. Generally, oil companies have confidence in subsea processing solutions, but costs are becoming a serious issue. If costs continue to increase, deployment of new technologies could be hampered.

Albacora Subsea Raw-Water Injection

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 24167, ’Albacora Subsea Raw-Water-Injection Systems,’ by L. Buk Jr., C.A. Andrade, J.B. Azevedo, E.J.J. Coelho, O.C. Costa, C. Kuchpil, A.G. Siqueira, and A.L.S. Souza, Petrobras, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. To increase the oil recovery in the Albacora field, significant water injection is required that was not considered in the initial project-development phases. Technical and economic constraints do not allow the use of conventional seawater-injection plants because current production units have no area available to implement a conventional water-injection system. Application of subsea raw-water-injection (SRWI) systems in the field involved challenges that required a detailed and systematic analysis to evaluate the technical feasibility and establish requirements for implementation. This alternative enabled seawater to be injected into the reservoir with minimum treatment by use of equipment installed on the seabed. Introduction In some offshore fields, mainly mature fields, the addition of conventional technologies to topside facilities can constrain the use of seawater injection. Conventional systems require the installation of too many pieces of equipment at the production units, which requires large areas that sometimes are not available. Other restrictions include swivel constraints on floating production, storage, and offloading vessels (FPSOs) and load limitations. One alternative is SRWI technology in which most of the system is installed at the seabed and seawater is injected with minimum treatment. This system has minimal effect on the topside- facilities footprint. The SRWI alternative involves technical challenges that include seawater compatibility with the reservoir rock and fluids, microbiological control, corrosion, water properties, reliability of the subsea equipment, and power, which limit the use of this technology in some scenarios. Petrobras established a project to evaluate and develop this technology, involving technical-feasibility studies and evaluation of various scenarios and preliminary specifications. During this project, Albacora-field reservoir studies indicated the need for large amounts of water injection, and SRWI became the only economically feasible alternative identified to address this demand. Albacora Field Albacora is a giant field in the Campos basin, approximately 100 km offshore Brazil, covering an area of approximately 235 km2, with water depths of 250 to 1100 m. The field was discovered in September 1984 and has an estimated oil-in-place volume of 4.4 billion bbl. Pilot-phase production started in 1987 with the FPSO P.P. Moraes. In 1993, a second development phase started with the semisubmersible P-24, which was replaced later by the definitive production system with two production units: the semisubmersible P-25 and the FPSO P-31, installed in 1996 and 1998, respectively. Field oil production peaked in 1999.

NEOGENE OIL AND GAS RESERVOIRS IN THE PROGRESO BASIN, OFFSHORE ECUADOR AND PERU: IMPLICATIONS FOR PETROLEUM EXPLORATION AND DEVELOPMENT

The Progreso Basin is an Oligocene to Recent forearc basin of pull‐apart/translational origin. In Peru, the basin contains proven petroleum reservoir sandstones of Early Miocene age at the Albacora field and the Barracuda‐4 well. In Ecuador, Middle Miocene sandstones tested oil at well Golfo de Guayaquil‐1, and Middle/Upper Miocene and Pliocene (?) sandstones produce gas at the Amistad field. Neogene sandstones are dominated by litharenites and feldspathic litharenites derived from uplifted and eroded Andean, Amotape (metamorphic), and oceanic crustal terranes. These are interpreted to have been deposited in neritic, brackish/coastal, and continental environments with locally steep gradients. The oil‐producing sandstones at Golfo de Guayaquil‐1 (∼12,300 to 12,418 ft RKB) and a gas‐producing sandstone of anomalously high porosity and permeability at Amistad‐1 (9,870 to 9,895 ft RKB) are of interpreted fluvio‐deltaic origin.Sidewall core and wireline log data indicate that reservoir storage capacity is good to very good. Porosity ranges from 15% to 30%, and is consistently greater than 20% where overburden is less than 10,000 ft. Compaction is the principal porosity occluding mechanism; sequential precipitation of authigenic chlorite, clinoptilolite (zeolite), and authigenic calcite has occluded porosity to a variable extent. Porosity preservation is assisted by disequlibrium compaction related to overpressuring throughout the basin.Reservoirs at the Amistad field have variable flow capacity. While the permeability of many sandstones is less than 20 mD, other sandstones, with probable Darcy‐scale permeability, have sustained commercial flows of gas since the onset of production in 2002. The flow capacity of offshore Peruvian reservoirs is limited. The most productive well at the Albacora field flowed at an average rate of only 451 b/d oil prior to abandonment.DST data from the Amistad field and the interpreted fluvio‐deltaic environment of deposition of some sandstones indicate that stratigraphic compartmentalization can be expected locally. Structural compartmentalization due to faulting occurs at Albacora field and is likely in other tectonically active areas. The sands are multistoried; they are interbedded with mudrocks and they typically are on the order of 100 ft or less in thickness.Gross‐sand thickness decreases westward and reservoir‐presence risk increases westward due to a number of factors including increasing distance from the sediment source; erosion of Miocene strata and complete truncation of Pliocene strata at an intra‐Pleistocene unconformity; onlap of the Neogene sequence onto the accretionary complex; and the presence of local bathymetric highs related to active mud diapirism.

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.

Abstract: Time-Lapse Resistivity Log Responses in Horizontal Wells, Namorado Reservoir, Albacora Field, Campos Basin, Offshore Brazil

Abstract: Time-Lapse Resistivity Log Responses in Horizontal Wells, Namorado Reservoir, Albacora Field, Campos Basin, Offshore Brazil

Abstract: High-Resolution Stratigraphy and Reservoir Heterogeneities of Upper Albian Turbidite Reservoirs of Albacora Field, Campos Basin, Offshore Brazil

Abstract: High-Resolution Stratigraphy and Reservoir Heterogeneities of Upper Albian Turbidite Reservoirs of Albacora Field, Campos Basin, Offshore Brazil