0 XX,700 XX,800 XX,900 B XY,000 XY,100 XY,200 XY,300 XY,400 XY,500
> Identifying compartments. Pressure data show several disconnected sand intervals (Track 2). Large pressure differentials between Points C and D indicate lack of connectivity. DFA stations and fluid samples were taken at six depths: Points A through F. DFA color analysis (Track 3) shows distinct differences between zones, as do the fluorescence data (Track 4). Components with more color have a higher optical density and should be at the bottom of the interval. Their presence higher in the column suggests compartmentalization. Varying intensity levels of fluorescence indicate different oil types. The lack of continuity and gradient disruption strongly imply many small disconnected compartments, which ultimately led to abandonment of the well by the operator.
The term compartmentalization covers a
variety of conditions that include continuous sealing barriers from sedimentary features, seal- ing faults, discontinuous sand lenses, pressure communication in the absence of flow communi- cation and regions of low permeability that inhibit fluid flow.28 A discontinuous fluid distribution is indica-
tive of a disruption of the normal fluid gradients that result from primary and secondary migration
28. Muggeridge and Smelley, reference 3. 29. Muggeridge and Smelley, reference 3.
Oilfield Review Autumn 09
30. Elshahawi H, Hashem M, Mullins OC and Fujisawa G: “The Missing Link—Identification of Reservoir Compartmentalization Through Downhole Fluid Analysis,” paper SPE 94709, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 9–12, 2005.
FluidsLab Fig. 12
of fluids during the hydrocarbon maturation pro- cess. This situation is further complicated by nonuniform temperature gradients; by reservoir restructuring during burial, uplift and erosion; and by other hydrodynamic events. If these processes cease, the fluids will return to their steady-state condition over geologic time. The absence of a continuous fluid gradient implies nonequilibrium fluid distribution and possible compartmentalization.29
ORWIN09/10-FluidsLab Fig. 12 33. Elshahawi H, Mullins OC, Hows M, Colacelli S,
Flannery M, Zou J and Dong C: “Reservoir Fluid Analysis as a Proxy for Connectivity in Deepwater Reservoirs,” presented at the SPWLA 50th Annual Logging Symposium, The Woodlands, Texas, June 21–24, 2009.
31. Mullins OC, Rodgers RP, Weinheber P, Klein GC, Venkataramanan L, Andrews AB and Marshall AG: “Oil Reservoir Characterization via Crude Oil Analysis by Downhole Fluid Analysis in Oil Wells with Visible– Near-Infrared Spectroscopy and by Laboratory Analysis with Electrospray Ionization Fourier Transform Ion Cyclotron Resonance Mass Spectrometry,” Energy & Fuels 20 (2006): 2448–2456.
32. Muggeridge and Smelley, reference 3.
34. For more on asphaltenes: Akbarzadeh K, Hammami A, Kharrat A, Zhang D, Allenson S, Creek J, Kabir S, Jamaluddin A, Marshall AG, Rodgers RP, Mullins OC and Solbakken T: “Asphaltenes—Problematic but Rich in Potential,” Oilfield Review 19, no. 2 (Summer 2007): 22–43.
35. Mullins OC: “The Modified Yen Model,” Energy & Fuels (January 19, 2010),
http://pubs.acs.org/doi/full/ 10.1021/ef900975e (accessed January 29, 2010).
36. Mullins, reference 35.
37. “Tahiti, Gulf of Mexico, USA,” http://www.offshore-technology. com/projects/tahiti/ (accessed November 30, 2009).
C D E F E F F C D D E C B B
Gamma Ray gAPI
100 8,400
Formation Fluid Pressure psi
A
Optical Density 9,200 0.5 A 3.5 0.12 A
Fluorescence Intensity 0.24
In a normal burial sequence, later-stage hydro-
carbon generation produces lighter hydrocarbons that rise until they encounter a sealing element. The anomalous presence of lighter or lower den- sity fluids at a point lower than expected in the oil column suggests stacked reservoirs or vertical compartmentalization. Discontinuous distribution of asphaltenes is also an indicator of compart- ments. In particular, increased concentrations of asphaltenes higher in the oil column indicate the presence of a sealing barrier (left). These dense asphaltene particles tend to sink, not float, in a single hydrocarbon column. The consequences of undetected compart- mentalization are reduced drainage efficiency and flow. With early identification of the degree and complexity of compartmentalization, engi- neers can design appropriate development schemes to mitigate its impact. They can also make better-informed decisions related to pro- duction facilities and reservoir economics.30
In
some cases, developing heavily compartmental- ized reservoirs may be uneconomical, at least with current technology and pricing.31 In the past, compartments were usually iden-
tified by well testing—drillstem tests (DSTs) and extended well tests. In deep water DSTs can become impractical, with costs approaching those of drilling a new well. Environmental issues from potential spills are also a concern. The most conclusive detection method is long- term production surveillance, but this may come too late for mitigation.32
These hurdles to identi-
fying compartmentalization are being addressed today through DFA Fluid Profiling techniques.33 Before the availability of DFA, reservoir engi-
neers looked at pressure communication to assess compartmentalization and connectivity. This approach is better suited to detecting isolated or unconnected pockets in producing fields. In virgin reservoirs there may be no pressure differential between unconnected elements. Relying on pres- sure differentials can also be misleading because compartments may have pressure communication in geologic time without flow communication in production time. A recent development in fluid analysis uses asphaltene concentration to indicate connectivity and flow communication.
Unlocking Reservoir Connectivity— Colloidal Nanoaggregates Asphaltene in oil is an example of a colloid—a mixture of one substance dispersed within another. Commonly consisting of an aromatic carbon core with peripheral alkane substituents, asphaltenes make heavy oils “heavy” and give oil color.34
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