As wells are getting deeper and more expensive, early identification of reservoir potential is necessary for critical decision-making, particularly in high-cost environments like deepwater exploration blocks. Demand is high in Brazil for services that positively identify and quantify not only the presence of hydrocarbons but also the flowing capability.
Petrophysical formation evaluation using LWD measurements has become a new requisite when drilling in complex-lithology carbonate reservoirs offshore Brazil. These reservoirs are difficult to characterize, presenting unique challenges for measuring porosity, estimating permeability, and assessing producible zones. The combination of two LWD tools – a compact multifunction LWD collar located close to the bit delivering traditional triple combo logs and advanced measurements like sigma and spectroscopy and a dedicated nuclear magnetic resonance (NMR) collar – provides suitable inputs for enhanced formation evaluation in this challenging environment.
Evaluating carbonates in the Campos basin
Drilling in complex carbonates with variable cementation is a slow process. ROP rarely exceeds 10 m/hr (33 ft/hr) and is commonly less than 5 m/hr (16 ft/hr). But the low ROP, while not too desirable in drilling terms, provides significant benefits for accurate petrophysical measurements since data of unprecedented quality are acquired without requiring additional rig time.
The first challenge in properly evaluating complex carbonate formations is computing an accurate porosity. In most Brazilian carbonate reservoirs the matrix composition is not constant due to the depositional environment and diagenesis. Identification of rock matrix is crucial since matrix density plays an important role in the porosity computation. The Quissam? formation (Maca? Group) reservoir has complex mineralogy consisting of carbonate rocks deposited during the Albian (Upper Cretaceous) age. The formation is part of the Campos basin. The reservoir interval is partially dolomitized in its lower half, with shoaling upward cycles from matrix to grain-supported rocks. In its upper part the reservoir is mainly composed of beds of grain-supported limestone with secondary siliciclastics-richer intervals.
Carbonates also have additional challenges related to porosity distribution, which tends to be more irregular than in sandstones. Total porosity may not be sufficient to predict rock producibility. Pore size distribution pattern has an equal or larger impact on permeability than the overall porosity. High water saturation does not necessarily imply water production. Small pores could store a significant volume of water that will not flow due to capillary forces. Identifying the amount of mobile water, or the difference between total water and bound water, is critical to predict which formation fluid will flow.
In carbonates it is useful to discriminate producing zones from micritic zones that may have similar porosities. Pore size distribution, which is closely related to the T-squared distribution delivered by NMR, is the key for doing so. The challenge is to have a reliable and repeatable measurement for a quantitative analysis.
Magnetic resonance while drilling
LWD technology now includes NMR acquisition capability providing information on textural differences vital for characterizing the most prolific zones and resolving formation evaluation as well as geosteering challenges.
The proVISION Plus magnetic resonance LWD service delivers accurate lithology-independent porosity and continuous T-squared distribution for real-time assessment of reservoir producibility. The T-squared waveform, streamed in real time from the downhole tool to surface and then from the rig to remote decision-making monitoring centers, contains embedded facies and permeability information.
Evolution of multimineral formation evaluation
Petrophysical evaluation in low-angle pilot wells is generally performed using traditional wireline measurements. In high-angle wells either LWD or combinations of wire-line and LWD logs are used. When using LWD data acquisition it has been fundamental to qualify the data provided while drilling to guarantee consistency and compatibility of the analysis performed.
The traditional approach used for petrophysical analysis is based on combining neutron, bulk density, and gamma ray measurements to estimate porosity, fluid properties, rock apparent density, shale volume, and mineralogy. The addition of deep- and shallow-reading resistivities helps differentiate water and hydrocarbons in virgin and invaded zones. These measurements are the foundation of petrophysics. But with limited inputs and many unknowns, formation evaluation and characterization in complex lithologies have significant uncertainty based on intuition and experience without guaranteeing a unique solution. This approach and relative risks are not acceptable in a high-cost deepwater environment.
In addition to the standard suite of gamma ray, resistivity, neutron porosity, and density measurements, acquisition of NMR, spectroscopy, and sigma measurements has proven critical to evaluating complex carbonate formations.
The availability of spectroscopy data greatly reduces the uncertainty by providing detailed, quantitative information about the rock mineralogy. Spectroscopy data are predominantly sensitive to rock composition and are used to directly drive the matrix determination based on predefined end points characterized in a laboratory. The methodology becomes highly scientific and removes the need for an educated guess. Focusing on matrix and fluids separately transforms a complex problem into the sum of two simpler analyses.
For fluid saturation computation a valuable measurement is sigma, which is especially sensitive to the amount of chlorine present and can easily differentiate formation water from hydrocarbons when water salinity is sufficiently high. In typical carbonate formations encountered in Brazil water salinity lies in the optimum range, providing a large contrast between hydrocarbons and water. Sigma is used to provide a resistivity-independent volumetric solution when invasion is small or, more generally, to characterize the filtrate-invaded zone.
The EcoScope multifunction LWD service provides both sigma and spectroscopy in addition to the traditional measurements.
To finalize the problem definition, NMR provides the missing information. The integrated porosity in the T-squared distribution up to the bound fluid cut-off defines the amount of unmovable fluids. With the recent improvement in accuracy and the extension of the T-squared distribution range toward short T-squared distributions, the NMR-derived bound fluid volume can be directly associated with the amount of irreducible water using a multi-mineral solver.
It is essential to have these advanced LWD measurements as soon as possible after drilling to facilitate informed decisions related to well placement and reservoir analysis. Collocation of the measurements also provides greater confidence in the interpretation, eliminating or reducing time-dependent invasion effects. The combination of the elements mentioned above allows evaluating mineralogy and fluid composition of the carbonate rocks encountered both in post-salt and presalt carbonates offshore Brazil. This analysis is performed in real time while drilling to estimate net-to-gross and reservoir quality. Images are used to compute dips and adjust borehole inclination to follow the reservoir sweet spot.
While drilling a complex carbonate reservoir in the Campos basin, an operator required an LWD analysis to identify producible zones. An 8½-in. high-angle borehole was drilled with synthetic oil-based mud using a bottomhole assembly that included a rotary steerable system and multifunction and magnetic resonance LWD services. All data were streamed in real time to enable complete formation evaluation while drilling.
In the petrophysical evaluation and textural analysis performed with LWD data, the top of the carbonate interval was shown to be tight, with no free fluid. This was followed by a progressive improvement in texture and porosity, achieving the best reservoir characteristics toward the bottom of the zone as illustrated by the micro-mesomacro porosity split. The permeability estimations were confirmed by modular formation dynamic tester stations. Overall, the quality of the estimation positively contributed to an understanding of reservoir behavior. The high-quality, real-time NMR data provided a comprehensive description of the carbonate reservoir rocks based on hydrocarbon detection to optimize placement of the wellbore. Drilling in carbonates inherently supports the LWD choice since drilling with relatively low ROP in these formations can help to acquire better quality log data without requiring extra rig time.
This article is based on Technical Paper IBP1218_12, which was presented at the Rio Oil and Gas Expo and Conference 2012.
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