Abstract— In this paper, a sequence stratigraphy and reservoir petrophysical analysis of a single oil well (Well H) has been prepared by using an available core data and wireline logging data with a view to characterizing the reservoir. In addition, petrophysical analysis initiated with lithology identification and lithological panels interpreted from well log data show that the study area is characterized Geological and Petrophysical Evaluation for an Oil Well Haval Hawez Petroleum Engineering Department, Koya University Email: [email protected]Mobile: +964(0)7504353785 Daniel Mitterrand Boulevard, Koya KOY45 AB64, Kurdistan Region - Iraq Zheno Ahmed Petroleum Engineering Department, Koya University Email: [email protected]Mobile: +964(0)7510688746 Daniel Mitterrand Boulevard, Koya KOY45 AB64, Kurdistan Region - Iraq Warzer M. Salih Petroleum Engineering Department, Koya University Email: [email protected]Mobile: +964(0)7512149335 Daniel Mitterrand Boulevard, Koya KOY45 AB64, Kurdistan Region - Iraq 1
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Abstract— In this paper, a sequence stratigraphy and reservoir petrophysical analysis of a single oil
well (Well H) has been prepared by using an available core data and wireline logging data with a
view to characterizing the reservoir. In addition, petrophysical analysis initiated with lithology
identification and lithological panels interpreted from well log data show that the study area is
characterized by sand-shale interbedding. Moreover, appropriate logs have been used to interpret
the reservoir for their fluid content, as are result; hydrocarbons versus water bearing zones were
outlined. Furthermore, the reservoir interval generally presents vertical anisotropy and great
heterogeneity with thick sand filled channel layers. The core involves mostly of red bed of sandstone
with some structure-less which is deposited in fluvial environment system. However, the core data
are relatively collated to wireline data to assess and survey the reservoir rock petrophysical
properties. A hydrocarbon water contact (HWC) was obtained from 1655 m. In addition, an average
Geological and Petrophysical Evaluation for an Oil WellHaval Hawez
Erosive surface with fining upward sandstone, interbedded calcite with coarse grain sandstone at the bottom overlain by intraformation mudclasts in the middle with fine grain sand at the tp. ( between 1652.33 to 1652.44, sample removed).
2 Erosive based successions. Erosive surface generally overlain by thick calcite grains followed by interbedded fine sandstone with intra formation mudclasts.
2m interval consisting of 3 erosive based successions. Interbedded mudstone with sand at the bottom. Erosive surfaces generally overlain by thin granule grains (conglomerate) followed by coarse sandstone.(between intervals 1649.25- 1640.37 and 1650- 1650.37, sample removed)
Stacked very fine sandstone at the bottom. Interbedded mudastone with sand followed by interbedded mica with sand at the top. (1648.12- 1648.33, sample removed)
No recovery.
3m interval consisting of stacked coarsening upward sandstone. Fine grained sand at the bottom followed by interbedded intraclasts of mud. (Between intervals 1646.58- 1646.5, 1645.20- 1645.09, and 1644.38- 1644.21 samples removed), (Between 1646to 1845.96 are no recovery).
coarse grained lateral accretion surfaces are observed.
Braided river closely in sequence with thin sheet flood that's fine grained deposits.
In upper parts, sheet floods and coarse grained lateral accretion surfaces are observed.
Arid terrestrial sands.
Laterally discontinuous and vertically heterogeneous arkosic sandbodies are likely to show better but porositiy is variable.Sandbodies areChannelized
Laterally discontinuous baffling shales and drapping sheet floods deposits unlikely to provide long term traps but as barriers will hinder production/recovery higher permeability sands.
TABLE 1. The description of the core (from 1644 to 1654 m).
TABLE 2. Shift table applied for depth matching after shifted down +1.35 m linearly for whole interval.
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2) Volume of shale
In general, volume of shale is used to accurate especially for bound water in porosity and the calculation
of water saturation in later stages.
Fig. 2. Core
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The main log which gives information about the presence of shale is the Gamma Ray log as well as
volume of shale is calculated by Gamma Ray log (eq.1).
IGR = GRLog−GRminGRmax−GRmin (eq. 1)
IGR illustrates shale index volume. GRmax is read from Gamma Ray log which shows the maximum
value of shale and GRmin shows clean interval of sand. Clean sand was selected because the sandstone
includes high value of potassium, Feldspar) which leads to a rise in reading of Gamma Ray log. The
following value GRmin =82 and GRmax =186 were used for calculating the shale volume curve.
3) Porosity
The main log which used for calculation porosity was density tool in the following formula:
∅ = ρma−ρbρma−ρf (eq.2)
Where:
ρma is the matrix density which is given by mudlog data , ρma= 2.71.
ρf is the density of fluid and is given by mudlog data, ρf= 1.00.
ρb is the bulk density from the log.
Because of the considerable presence of shale in the reservoirs, the measured porosity was corrected for
the volume of shale using Dewan (1983):
φcorr=φ−V sh∗φDsh
Where:
φcorr=shale corrected density porosity
φ =Density porosity
Vsh=Shale volume
φDsh=density porosity of nearby shale
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The correlation between core porosity and calculated core porosity is poor as seen in Fig.9. As a result of
structure or digenetic features in the rock, the crossplot scattering points show worse correlation. The
changes between recording porosity by wireline tools and testing porosity in the laboratory by fluid
injection may cause by the amount of mineral dissolution.
4) Water Resistivity
In water bearing zone, Archie's equation uses to calculate the amount of water resistivity. The following
equation use to calculate water resistivity (Rw):
Swn =
F RwRt (eq. 3a)
Where, Sw is the water saturation, n is the saturation exponent.
In water bearing zones assumed water saturation is a 100 percent (Sw=100%), we get:
Rw= RtF (eq. 3b)
Where F is the formation factor and calculated using Humble formula (eq.3c), a: is the constant value
(a=0.62 in sandstone), m: is the cementation factor (m=2.15 in sandstone).
F = a∅m (eq. 3c)
The density log measured porosity which is used in Humble formula using equation 2.
Where: at depth 1723m water resistivity (Rw) and were obtained and then it is calculated by using Gen-6
chart. In this process, where temperature is 136℉ at 1816m at the bottom hole depth (given from the mud-
log) and the mean surface temperature was considered to be around 9℃ (or 48℉). The final temperature
was 135℉ .
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So, Rw is 0.033 ohm at 135℉ and 1723 m deep. After calculating Rw, the amount of salinity of the water
formation can be found out using from Gen-9 chart. The Salinity of the water formation must be about
130,000 ppm at 134℉ and Rw = 0.0343.
Water saturation based on equation 3a and it was calculated using Archie model.
5) Permeability prediction from porosity
The density tool can be used to calculate porosity for correlation with permeability in the absence of core
porosity data.
It may be a difficult exercise in wells where the core data does not exist for permeability prediction. In
addition, some additional data from log and core plugs should be taken from another well to evaluate the
reservoir characteristic behavior better.
6) Lithology
It is a bit trivial in lithology determination for the logged interval. After calculation of shale volume as
previously mentioned, lithology composition is calculated with linear equation for the chosen curves, i.e.,
density, neutron, and delta-t. This is iterated repeatedly until the smallest error. Cross-plot of density
neutron for particular interval was used as double check with the result along with sedimentary log from
core. Figure 8 shows the result is confirmed each other and the calculation can be used for the rest of
interval. Yellow
coloured scattered point in the cross plot is from the whole interval, while the red coloured is from
particular interval of 1630 – 1650 m to have range of 10 m in the core logged.
C. Net-Pay Reservoir Calculation
The knowledge about the net pay is significant for the volumetric hydrocarbon estimation, a practice that
supports the merit of the petroleum industry. There is not general definition of net pay yet, there is not
universal approval of its role in integrated reservoir analysis, there is not identified way for estimating it,
and there are different survey on how to make use of it. Partially for these reasons, net-to-gross pay makes
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up a main source of doubt in volumetric reserves estimates, second merely to gross rock volume. The
process of the recognition of net-pay cutoffs discuss over the years. The access is data-driven, in that it uses
what is known, and also fit-for-purpose, in that it receives statement of reservoir conditions. The result is a
sounder basis for united net pay into volumetric evaluates of extreme recovery and therefore resources of
hydrocarbon.
1) Porosity cutoff
While logarithmic core permeability plotted versus core porosity, the porosity cutoff is chosen for 5.0 mD
of permeability value as shown in Fig.3.
Porosity cutoff ≥ 13
2) Shale cutoff
Porosity is first found by using density tool and is plotted against shale volume curve line. The shale
cutoff is then specified according to previous porosity selected cutoff as seen Fig. 4.
Volume of shale cutoff ≤45
Fig. 3. Kh vs Core plug Phi
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3) Water saturation cutoff
The water saturation cutoff is selected using porosity plot versus water saturation as shown Fig.5.
Furthermore, water saturation is found by water resistivity first and porosity is specified by density tool.
Water saturation cutoff ≤ 73
Fig. 4.
Fig. 5. SwE vs
Effective Phi
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VI. DISCUSSION
A. Petrophysical Summary Report
The sharp decrease of reading resistivity tool shows the hydrocarbon water contact while comparing the
signal of Neutron and Density tools at about 1655 m depth. Although, with decrease of both Neutron and
Density tool can detect gas zones, there is not gas present.
Totally, logged interval was around 170 m and the gross interval was estimated 120 meters and net to
gross ratio was 0.5 m. The resistivity curves was run to provide total resistivity (Rt) and flushed zone
resistivity (Rxo) and then to evaluate water resistivity (Rw). After borehole correction using down-hole
electrical logs, washout was noticed of permeable zone around 1730m and 1755m as well as
unconsolidated clays observed around 1768m. Porosity was found by density tool and permeability was
predicted by various permeability predictors. The followed table shows the petorphyscal summary which
has been done (Table 3):
B. Statistical Analysis:
In future study, heterogeneity, the variation of permeability and anisotropy are analyzed with the assist of
statistical analysis. Therefore, the well data is demanded for spatial information to help the growth reservoir
model and further simulation.
1) Heterogeneity, Average Permeability and Anisotropy
The convenient average should be chosen for analyzing horizontal permeability (Arithmetic, Geometric
or Harmonic average). In fact, this based on the distribution of geological layers and bed geometry. There
are available core data between 1610 to1680 meters and the statistical analysis was created to measure the
degree of heterogeneity in the environment system. The variance of coefficient shows a high degree of
heterogeneity in the permeability data, whereas the variance of coefficient illustrates a low degree of
heterogeneity (Table 3).
As far as the histogram is concerned, porosity illustrates symmetrical distribution that means as a single
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population, whilst permeability histogram shows a skewed distribution and includes two population
evidence data (Fig.6). In addition, the Lorenz plot obviously shows high degree of heterogeneity (Fig.7).
Table 3. Statistical data for Kh and porosity heterogeneity determination.
Fig. 6. Shows histogram for porosity and horizontal permeability.
Analyzing the data of an available core and a suite of well logs has resulted in detailed Petrophysical
analysis and well-log sequence stratigraphy of the well. Adequate lithological interpretation and description
was also carried out with the delineation of hydrocarbon bearing reservoir sands.
In general, the grain size is medium sand porosity which is laid down in an arid environment like a
braided fluvial environmental system. The sand bed is laterally and vertically anisotropic and
heterogeneous, while horizontally flow dominating. The body of faces are baffled by heterogeneous
subsurface.
Although, the net pay is around 17.3502 meters, it may be increase significantly laterally for the layers.
There were no significant signatures for faulting.
Three depositional environments have been interpreted namely: the channel and shoreface environment,
fluvial channels and shoreface sands and the reworked sandstone units. Porosity estimates is highest
observed in the channel and shoreface environment.
To improve the information about the subsurface and reservoir flow unit areas should be more data
collected from other wells in the same area to better understanding of the reservoir characteristic behavior.
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Newell, A.J., (2006) “Formation SW England fluvial sandstone aquifers (Otter Sandstone Calcrete as a source of heterogeneity in Triassic)”, Geological Society, p119-127, v.263, Geological Society, London, Special Publications.
Ola-Buraimo, A.O, J.E. Ogala, and O.F. Adebayo. (2010) “Well-Log Sequence Stratigraphy and Paleobathymetry of Well-X, Offshore Western Niger Delta, Nigeria”. World Applied Sciences Journal. 10(3):330-336.
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