Group Project- An extract from original report

1
PVT ANALYSIS
CORE & SCAL
Project Report - 2012/2013
MSc Petroleum Engineering
Mukesh Mathew

[PVT ANALYSIS – CORE-SCAL] June 11, 2013
Heriot-Watt University 2
PETROPHYSICS
The petro-physical data from log(paper and digital),core and SCAL data has been collected and
analysed to arrive at characteristic parameters of the reservoir. Comparison between the data has
reduced uncertainty and given data within a range.
Models within Terrastation have allowed analysis of the exploratory wells. This was done with
V-Shale, porosity, permeability, and saturation models. The core data was first overburden
corrected and depth matched before analysis was carried out. Statistical analysis was carried out
on the porosity and permeability values. The porosity average was in the range of 15-21% and
the permeability average was in the range of 210-350mD.
PVT ANALYSIS
The PVT analysis were carried out on the samples taken from wells 2,5 and partial PVT analysis
on well 6.All the PVT analyses were carried out by Core laboratories, Texas and Core
laboratories, UK. For well 2, two samples were taken from between the depths 8616-8693 feet
whereas for wells 5 and 6, samples were taken from 8500-8515ft and 9754-9804ft respectively.
Well 2 data can be considered as representative of the formation as it was taken within the
producing zone. Test 2(Pb=2140psig) carried out on well 2 has been selected whose bubble
point pressure value is (test1-Pb=2061psig) slightly higher than test 1.
The data for well 2 was obtained from Drill Stem Test 6(PT1 and PT2), this was characterised by a
last reservoir pressure of 3852 psig and a reservoir temperature of 2480
F. The field stock tank oil
gravity varies from 33.9-34.1o
API. The produced GOR from test 1 and test 2 is 352SCF/STB and
319SCF/STB respectively.
From the flash vaporisation test, the specific volume was obtained to be 0.02669 and compressibility
of oil as 12.78*E-6. The density of oil at the initial reservoir pressure is 45.06lb/ft3
.
The differential vaporisation test allowed analysis of the solution gas oil ratio and oil formation
volume factor, below the bubble point.
From the separator test, the oil formation volume factor at the saturation pressure was obtained to be
1.387 RB/STB and it was 1.356RB/STB at initial reservoir conditions. The solution gas oil ratio
above bubble point is calculated to be 507 SCF/STB.
The hydrocarbon composition of the reservoir fluid was determined from the separator products
which were recombined to producing gas oil ratio. The oil is determined to have 0.35% mole
fraction CO2 whereas the hydrogen sulphide content is NIL. The major components are methane and
heptanes+ which constitutes 30.27% and 43.25% mole fractions respectively.
From the geochemical characterisation, oil from the Palaeocene formation is found to have an
average density of 33.5 API and 36.9 API from the Jurassic zone (lower reservoir). The oils from
both reservoirs are low in Sulphur and nitrogen content, having values less than 0.35wt%.

PVT Summary

PVT analysis – Calculations
Above Bubble point
Oil formation volume factor (Bob) at Pb = 1.387 RB/STB
Initial oil formation volume factor at test reservoir pressure, Boi =
(Volume of bubble point)*(Volume of reservoir oil)
(Volume of stock tank oil)*(Volume of bubble pt oil)
= 1.387*0.9785
= 1.357 RB/STB
Solution gas oil ratio (GOR) = 507 SCF/STB
Produced GOR = (Separator liquid production rate) x (Primary separator gas to liquid ratio)
0.9 * Separator liquid production rate
Assuming 10% water cut,
= 3943 x 287
0.9 x 3943
= 319 SCF/STB
Vb = 0.02269 ft3
/lb
Initial oil density = 1/ (0.02269 x 0.9785)
= 45.286 lb/ft3
Below Bubble point

Hydrocarbon Analysis

CORE DATA ANALYSIS
Porosity and permeability data from obtained cores was provided for 3 wells (well 2,3 and 5) at
varying points within the reservoir. These were analysed statistically with multiple models
including various different averages, semi-variogram, sample efficiency, Lorentz plot, Modified
Lorenz plot and porosity cut-off calculation. Extensive SCAL data was provided for 4 wells, this
gave a better understanding of the reservoir rock.
The core data has been corrected for overburden. This correction reduced the permeability and
porosity of the samples as it assumes compression of the cores to reservoir pressure. This was
necessary as the cores were tested at surface conditions. Core data has also had to be depth
matched in well 2.This was carried out due to evidence collected at the core store, it gave a better
match with the log data, and this error could have arisen from the stretch of the tubing on which
the coring tool was run.
SCAL
The capillary curves and relative permeability curves were provided for wells 2, 3 and 6. The
capillary curves were first converted from air-water to water-oil curves. These were then
normalized using the modified Leverett J-function and a single table was created. The given
relative permeability curves were grouped together and an effective relative permeability curve
were created.
The wettability tests were carried out on 10 core samples using the Amott-Harvey method. The
average wettability index is +0.1479, this indicates the formation is slightly water wet.
I) Capillary curves normalization
The air-water capillary pressure curves were determined by the centrifuge method, using air as
the displacing fluid. Hence it was important to convert it to water-oil capillary pressure curves.
For this the following equations were used.
Pc air/mercury = 5 Pc air/water & Pc air/mercury = 10 Pc water/oil
i.e., 5 Pc air/water = 10 Pc water/oil

Pc water/oil = 0.5*Pc air/water
The modified Leverett J-function has been used to normalize all the capillary curves and to create
a single Pc vs. Sw curve (see below) for the static model using the following equations:
Modified Leverett J-function = Pc(K/Ø)0.5
Normalised wetting phase saturation, Sw*
= (Sw – Swc)/(1-Swc)
II) Relative permeability curves
The water-oil relative permeability and gas-oil relative permeability measurements were made on
the preserved core samples (coated in paraffin wax). According to this water-oil and gas-oil
relative permeability tables were created by grouping it together and these were used in the
dynamic model. The average wettability index obtained from Amott- Harvey method indicates
that the formation is slightly water wet.

Group Project- An extract from original report

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