In 2004, the Mangala, Aishwariya, and Bhagyam fields were discovered in
Rajasthan, India. In these high-permeability paraffinic reservoirs, viscosity
is one of the main factors controlling performance. Pressure, volume, and
temperature (PVT) data show areal and vertical variations in crude properties.
Meter-by-meter geochemical core analyses corroborate vertical variations in oil
composition. Continuous wireline measurements of nuclear magnetic resonance
(NMR) properties and station NMR properties from wells drilled with both
water-based muds (WBM) and synthetic oil-based muds (OBM) were also used to
calculate a viscosity profile. This paper correlates results from all
techniques and shows how NMR measurements can provide oil viscosity profiles in
compositionally complex pools.
Black-oil PVT samples typically test several meters of reservoir, while
Rajasthan geochemical data are available at meter scale. NMR logs provide
continuous data, and calibrated to PVT and geochemistry, they can provide the
most detailed picture of in-situ viscosity variations.
Results were used to construct a detailed spatial description of the
reservoir’s in-situ oil viscosity. The NMR data helped to define a zone of
biodegraded oil up to ~25 m thick above the oil-water contact (OWC) and showed
thin accumulations of higher-viscosity oil on top of minor shale layers within
oil columns. The major conclusion is that detailed in-situ oil viscosity
profiles can be developed from conventional wireline T2 measurements.
Introduction and Available Data
This paper presents oil viscosity estimates for Mangala and Aishwariya using
a variety of wireline data and a variety of methods. The objective has been to
investigate and utilize any correlations between wireline and laboratory NMR
measurements and in-situ PVT properties (especially oil viscosity) measured on
oil samples collected from the fields. Further, correlations have been made
with geochemical analyses taken from field cores. The result is the estimation
of in-situ oil viscosity as a function of depth in the wells where appropriate
data are available, along with fieldwide correlations of viscosity as function
of height above the OWC. One desirable property of the viscosity estimates is
that they have the same depth resolution as the wireline log data from which
they are derived.
The data available consist of complete routine suites of wireline logs,
combinable magnetic resonance (CMR+) logs, magnetic resonance fluid (MRF)
station measurements made with CMR+ equipment, PVT oil properties made on
reservoir oil samples, and detailed geochemistry data. Table 1 summarizes, by
well, the data types available, and Table 2 summarizes the PVT data available
for the wells in Mangala and Aishwariya fields.
The Mangala, Aishwariya, and Bhagyam fields lie within the Barmer basin, a
narrow NNW-SSE oriented rift basin formed during the Palaeocene epoch in
northwest India. The oil is contained in the Fatehgarh Group sandstones and is
trapped in tilted fault block structures. The Fatehgarh Group is a Palaeocene
fluvially dominated unit consisting of ~250 m of medium- to thick-bedded, fine-
to coarse-grained sandstones interbedded with iron-rich mudstones. The sands
were deposited in a variety of braided to sinuous meandering channels and are
composed almost entirely of mature quartz grains. The Fatehgarh Group has been
subdivided into five units. At Mangala field, they are designated FM1 to FM5,
and at Aishwariya field, they are designated FA1 to FA5.
The Fatehgarh contains excellent reservoir-quality sands with porosities of
18 to 33% (average 25%) and permeabilities of up to 20D (average 5D).
Net-to-gross (N/G) sand varies from 45% in the Upper Fatehgarh to +90% in the
the Lower Fatehgarh (Rathore et al. 2006). The total STOIIP in the Mangala,
Bhagyam and Aishwariya fields is estimated at 2,054 million STB, with 1,293
million STB of that contained in Mangala. Wireline pressure data and well
interference tests together indicate that each field has its own unique
fieldwide OWC, and it is concluded that although faults exist,
compartmentalization in each field is minor to nonexistent.
Petrophysical and Rock Property Data
Petrophysical modeling was conducted for eight Mangala wells, six Aishwariya
wells, and ten Bhagyam wells. The interpretation was performed using a
deterministic approach and generated values for wet-clay volume, effective and
total porosity, and effective and total water saturation. The volume of clay
was derived using a combination of gamma ray and neutron-density techniques.
Total porosity was calculated using the density log with variable matrix
densities, and effective porosity was calculated from the total porosity and
the estimate of clay volumes. Water saturations were calculated by use of the
dual water equation.
While developing the petrophysical model, an effort was made to use uniform
petrophysical modeling procedures for each field. Extensive laboratory-derived
routine core-analysis data were used, and effort was made to make the model
consistent with the available core and geological data.
In addition, numerous special core analyses (SCAL) have been conducted to
determine capillary pressure, wettability, relative permeabilities, electrical
properties, and the initial and residual oil saturations. All native-state and
restored-state SCAL results indicate a mixed- to slightly oil-wet reservoir,
with Amott-Harvey wettability indices averaging –0.35. These tests also
indicate that very low initial water saturation and residual oil saturations
are possible with the application of waterflooding.
© 2008. Society of Petroleum Engineers
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- Original manuscript received:
22 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
10 October 2007
- Manuscript approved:
8 December 2007
- Version of record:
20 June 2008