CASE STUDY
Insitu Density Sensor Measurements Identify Fluid Composition and Contacts
Downhole fluid analysis of channel sands in Nigeria deepwater appraisal well
based on Quicksilver Probe focused extraction
CHALLENGE
Dynamically investigate formation fluid
density at reservoir conditions in an
appraisal well drilled with oil-base mud.
SOLUTION
Combine InSitu Density* reservoir fluid
density sensor with Quicksilver Probe*
focused extraction to obtain accurate
density measurements under flowing
conditions and conduct downhole fluid analysis.
The importance of accurate fluid density information
Determining fluid density is a primary objective of formation evaluation because that
measurement significantly influences field production and economics. The ability to obtain
quantitative fluid density measurements at reservoir conditions and in real time from a deepwater
vertical appraisal well drilled with oil-base mud would improve understanding of the formation
fluids and the reservoir for optimizing a subsequent drillstem test.
Formation Pressure, psi
Composition, wt %
Methane Ethane Hexane
2,900
3,200 0
Fluid Density, g/cm3
0.5
1
CO2
Drawdown Mobility,
mD/cP
1 0 100 0.1
10,0000
TVD
(MD), m
Gamma
Ray, gAPI
Petrophysical
Analysis
1,700
(1,700.1)
RESULTS
Acquired accurate density data input for real-time downhole fluid analysis to optimize the logging investigation and subsequent operations.
1,720
(1,720.1)
0.14 g/cm3
1,740
(1,740.1)
Station A
1,760
(1,760.1)
0.71 g/cm3
Station B
1,780
(1,780.1)
Station C
0.97 g/cm3
1,800
(1,800.1)
1,820
(1,820.1)
Downhole fluid analysis during openhole logging provided the operator with critical
insight to the fluid density, formation pressure, and the pressure gradient along with
downhole compositional analysis and fluid mobility values.
Formation Evaluation
CASE STUDY: Insitu Density sensor identifies fluid composition and contacts, deepwater Nigeria
Downhole insight in real time
The InSitu Density sensor was deployed with innovative Quicksilver Probe focused extraction,
which diverts filtrate-contaminated fluid to the perimeter of the probe to collect pure reservoir
fluid into the extraction flowline. The separation of pure reservoir fluid makes it possible to
accurately conduct downhole fluid analysis, even in oil-base mud. Under flowing conditions, the InSitu Density sensor uses dual resonance modes to directly compute density from
resonator-fluid interaction, with the measurement quality assessed against standard-fluid
characterization parameters.
The toolstring was also configured with optical fluid analyzers, conducted pressure pretests,
and collected PVT fluid samples.
Oil zone confirmed and characterized
InSitu Density sensor’s measurements shown from three sampling stations in the oil zone are
consistent and comparable with values determined by pressure gradient analysis and were
confirmed by subsequent PVT sample analysis. Because real-time measurement of fluid density
directly yields the slope of the pressure gradient, the fluid contacts can be readily identified.
The log shows three pressure gradients, corresponding to gas, oil, and water and all in pressure
communication. There are no indicators of compartmentalization or compositional grading.
The composition of the oil was also determined in real time by downhole fluid analysis of the fluid density measurements and optical spectrometry data.
With this information available during logging, the operator was able to rapidly assess the fluid composition and location of fluid contacts to guide the operation and then design a drillstem test.
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