Asphaltene molecules readily combine—or aggregate—into small particles called nanoag- gregates, which are often their dominant form in crude oils. At high concentrations, nanoaggre- gates can further combine to form clusters (right). Both the nanoaggregates and clusters are found as colloidal dispersions in crude oil.35 Fluids specialists use color from DFA measure-
ments to estimate the concentration of asphaltenes in reservoir fluids. Similarities in color can then be used to identify compositionally similar fluids from different locations within a reservoir. This infor- mation is being used to infer flow connectivity and understand reservoir architecture. Asphaltene gradients are used to understand
fluid distribution in a reservoir, and they can occur as a result of GOR gradients. A characteris- tic of low-GOR fluids is that they can dissolve (or disperse) large amounts of asphaltenes. High- GOR fluids can dissolve very little asphaltene; methane, the simplest alkane, dissolves no asphaltenes. In addition, gravity segregation tends to concentrate asphaltenes at the base of a fluid column; the magnitude of this effect is strongly influenced by the size of the asphaltene particles. Both GOR and gravity work to concen- trate asphaltenes at the lowest point in the reser- voir, while thermally driven entropy tends to disperse the asphaltenes. Sealing barriers or flow restrictions disrupt
the movement and migration of fluids and, as a consequence, segregate fluids with different asphaltene concentrations. The presence of a discontinuous asphaltene concentration laterally or vertically within the reservoir explicitly indicates a boundary to fluid flow. If the asphaltene gradient is the same across
a reservoir, and especially if it is in equilibrium, connectivity is implied because it takes geologic time and fluid movement to establish an equilibrated asphaltene gradient. Sealing barri- ers all but preclude equilibrium distributions of asphaltenes. It is now possible to model the distribution of
asphaltenes within a reservoir once the asphal- tene colloidal particle size has been determined.36 This requires not only accurate measurement of the relative asphaltene concentration, but also an accurate measurement of GOR vertically and laterally in the reservoir. The InSitu Fluid Analyzer service provides
measurements with sufficient resolution and accuracy to compare fluids across a reservoir. These data may then be incorporated into an equation of state (EOS) to model the asphaltene distribution. If the measured gradient fits the
> A geologic model showing the upper and lower horizons of the Tahiti field. The steeply dipping beds of the deepwater Tahiti field, whose sands are shown here in this 3D facies model, lie beneath an 11,000-ft-thick salt canopy. Allochthonous salt buoyancy caused the field to tilt. Since the reservoir is not a rigid body, tilting the field results in faulting. The biggest risk factor in field development is whether these faults are transmissive and thus contribute to reservoir connectivity. Seismic models cannot provide this information, but DFA data have proved beneficial in identifying connectivity within the field.
Winter 2009/2010 49
Asphaltene Molecule
Nanoaggregates Nanoaggregate
Asphaltene
Clusters of Asphaltene Nanoaggregates
Cluster
N
> Asphaltene molecular structures. Asphaltenes (left) can take many forms but are characterized as aromatic rings (green) with alkane chains. The rings may be fused, meaning they share at least one side. The rings may also contain heteroatoms such as sulfur, nitrogen, oxygen, vanadium and nickel. The molecule on the left contains a nitrogen [N] heteroatom. Asphaltene molecules form nanoaggregates (center) in oils. High concentrations of nanoaggregates form clusters (right) in heavy oils.
EOS model, connectivity is indicated. The ability of DFA to link asphaltene concentrations to connectivity was demonstrated by a multiwell, multiyear study in the deepwater Gulf of Mexico Tahiti field.
Asphaltenes, Colloids and Equilibrium Located approximately 190 mi [300 km] south of New Orleans, and in a water depth of 4,200 ft [1,280 m], the Tahiti field discovery well was drilled in 2002. With a total depth of 28,411 ft [8,660 m], the well epitomizes the potential risks and rewards of deepwater exploration, encoun- tering more than 400 ft [122 m] of net pay.
Oilfield Review Autumn 09
and appraisal wells Exploration
Subsequent appraisal wells found net-pay inter- vals in excess of 1,000 ft [300 m]. Data from what was at that time the world’s deepest successful well test indicated a single-well production rate greater than 30,000 bbl/d [4,800 m3/d].37 The reservoir consists of several stacked
Miocene turbidite sand intervals buried beneath an 11,000-ft [3,353-m] thick salt canopy. After the initial discovery two appraisal wells with sidetracks were drilled, and extensive pressure data, DFA data and fluid samples were acquired for the producing intervals (below). The two pri- mary sand layers—the M21A and M21B—are in different pressure regimes, and pressure testing
FluidsLab Fig. 13
ORWIN09/10-FluidsLab Fig. 13
production well
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