Petrophysical Analysis
2,900
Formation Pressure psi
Fluid Density 0.5 g/cm3
Moved Gas Gas
3,200 Composition 1 0
Methane Ethane Hexane wt %
Gamma Ray
gAPI 100 0 100 0.1 1,720 1,740 GOC
Station B Station A
Station C OWC 1,800 1,820 1,760 1,780
Drawdown Mobility cP
100,000
Water Oil
Sand
Bound Water Clay 1
> Fluid contacts from pressure and InSitu Density data. Fifty-six pressure points were sampled to construct a pressure profile curve (Track 1). Data indicate fluid changes at 1,798 m and 1,748 m. The fluid composition data from the InSitu Fluid Analyzer module show oil and gas (Track 2). Stations A, B and C confirm that the oil density (red triangles) is consistent throughout the oil interval. From this analysis the operator confirmed the fluid density, quickly identified fluid contacts and developed a subsequent DST program that validated the DFA analysis.
The pressure-sampling program included 56
pressure pretests along with fluid profiling and sampling at seven depths across the reservoir interval. A technique using an excess-pressure plot indicated pressure communication within the reservoir and a single producing unit with compositional grading. Three gradients were identified, corresponding to water, oil and gas— all in pressure communication (above). A mea- surement station that included the InSitu Density sensor was performed at 1,754.5 m [5,756 ft] MD, which is near the top of the oil zone. Laboratory PVT analysis of the recovered fluid
from that station yielded an oil density of 0.70 g/cm3. The InSitu Density sensor measured a density of 0.71 g/cm3. These values compare favorably with each other—within 0.01 g/cm3, the accuracy typi- cal of fluid density measurements made in the con- trolled environment of a laboratory. With DFA data that included fluid density, the
operator was able to quickly analyze the fluid composition, determine fluid contacts and assess
reservoir connectivity. Because the Fluid Profiling technique revealed no sealing features or poten- tial compartmentalization, the operator was able to proceed with the original development plan.
Downhole Laboratory of the Future What began as a means of quantifying sample qual- ity has evolved into laboratory-grade measure- ments that quantify in situ fluid properties. As the nature of DFA measurements such as the InSitu Family service expands, so too have applications. The future of DFA may take two directions:
LWD-based services and new measurements. Today, service companies have tools that can pro- vide pressure profiles while drilling. Eventually, elements of the downhole fluids laboratory will be incorporated into these services, enabling the measurement of real-time fluid properties before deep invasion of drilling fluids occurs. New techniques are also in development, such
Oilfield Review Autumn 09
FluidsLab Fig. 23 ORWIN09/10-FluidsLab Fig. 23
as an accurate measurement of in situ fluid viscos- ity and concentrations of other components.
Viscosity, for example, has significant impact on fluid recovery and therefore field economics. However, surface measurements of viscosities often include a host of effects that may render them inaccurate or invalid. To better understand the reservoir and maximize production, reservoir engineers will be able to use viscosity measure- ments to analyze fluids flowing from the reservoir before they undergo phase changes due to pres- sure and temperature variations. Reservoir development will never be as
simple as inserting a long straw into a lake of crude oil and sucking it out. For now, however, the reservoir engineer has an exten- sive portable laboratory to send downhole and help unravel the complexity of in situ fluids, while also helping clarify understanding of reservoir architecture.
—TS
54
Oilfield Review
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