A Vertical Offshore Wildcat Biology Essay

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Well SEATH-1 is a vertical offshore wildcat well drilled to evaluate a prospect. The evaluated interval was 4800-5490ft and it consists of claystones interbedded with sandstones. The status of the well is oil discovery. The total depth drilled is 6718ft and the well elevations above mean sea level are: Kelly Bushing (KBE) 89.00ft; Drill floor 88.00ft; Water depth 196.00ft. All the log depths were measured from the drill floor elevation.

The target reservoir was drilled with an 8.5 inches bit using an oil based mud (OBM) system with mud weight 9.100lb/gal. The calculated bottom hole temperature is 206°F and that of the surface/seabed is 50°F. The downhloe temperature gradient is 2.42°F/100ft (Table1).

The Gamma ray, Sonic, Photo-Electric Factor, Array Induction Resistivities, Density and Neutron logs were used for the evaluation. Five 30ft core were cut at intervals 4851-4881ft, 4881-4911ft, 4911-4941ft, 5195-5225ft and 5225-5255ft with recovery of 100, 100, 73, 100 and 90% respectively. Routine core analysis was carried out on the core plugs cut at approximately 1ft interval. No Special core Analysis measurement has been made on the core plug to date, however, formation resistivity factor at ambient laboratory condition in nearby wells indicates a cementation factor (m) of 1.8, assuming Archie's constant (a) is 1.0. The drill stem test results at intervals 5202-5225ft, 5232-5236ft, and 5002-5046ft gave a result of the gas rate, the oil rate, the fluid property and the interval permeability (Table 3) No resistivity index data are currently available, but the regional formation waters are relatively fresh with a salinity <10,000ppm NaCl equivalent but are known to vary within sands.

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The oil water contact (OWC) interpreted from the log plot (fig. 1) is at a depth of 5350ft. The pressure versus depth plot (fig. 5) indicates that the free water level (FWL) is at a depth of 5364ft. From the pressure vs depth plot, there are two oil columns with different gradients (they are not in communication).

1.2 Objectives of the evaluation

The petrophysical evaluation of well SEATH-1 was undertaken to review available data, identify lithologies and compare results obtained from cores with that obtained from logs, well test; evaluate the clay volume, porosity and saturation; provide the average reservoir properties of porosity, saturation and net thickness of all major sand bodies; identify hydrocarbon bearing zones and contacts, determine the hydrocarbon type (oil or gas), and provide a summary on the well results indicating potential issues that the management needs to be aware of when assessing the prospect.

2.0 Data Review

The following data were available for the evaluation of well SEATH-1.

2.0.1 Well Data

The well data is a summary of the well information it includes the name of the well, the field, the type of well, the status, the reservoir formation and total depth of the well. Also included in the well data table are the total depth of the well, elevation datum details, the mud physical properties (mud weight, fluid base, and constituents), the size of the drill bit and the borehole temperature (Table1).

2.0.2 Raw Log Data

The raw log data is the real data prepared in the field by the contractor. It includes the measured depth of the well, the hole size in inches as measured by the calliper tool, the litholgy/porosity logs; Gamma ray (GR), Sonic (DT), Density (RHOB), Neutron (NPHI),and Photo-Electric Factor (PEF). Also included in the raw data are the Total Vertical Depth Subsea (TVDSS) of the well in feet and the Array Resistivity Logs.

2.0.3 Formation Pressure Data

Formation pressure is the pressure in the pore fluid that occupies the pore space, at any depth the pore fluid pressure should be the same across the accumulation. Formation pressure data of 36 points were acquired using a wireline Repeat Formation Tester (RFT) tool (Table 2) and were plotted against the true vertical depth obtained from the raw data. From this plot the Oil and water gradient along with the position of the Free Water Level (FWL) were obtained (fig. 5).

2.0.4 Core Data

The core data is based on the driller's depth; it includes the core depths, equivalent log depths and their corresponding permeabilities, porosities and grain densities. A shift of -5ft was applied to the core depth to match it with the wireline log depth.

2.0.5 Drill Stem Test Data

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The test result obtained from the drill stem test is shown in the table below.

Table: 3 Drill Stem test

DST

Interval

Gas rate

Oil rate

Water Rate

Fluid Properties

Interval Permeability

1

5202-5225

5232-5236

0.1 mmscf/day

665 bbls/day

0

Oil 27.6° API

176 mD

2

5002-5046

0.03 mmscf/day

306 bbls/day

0

Oil 32.9° API

1070 mD

2.1 Techniques and Parameters

2.1.1 Clay volume

The clay/ shale volume was estimated using single log technique the (Gamma Ray log) and cross plot techniques from Neutron- Density cross plot (fig. 3), Neutron - sonic cross plot (figure 4) and GR X plot (fig. 2) where non clay matrix is homogeneous. The fifth zone (Table 4) in the lithological unit was used to define the clay parameters, from this the GR X-plot, the matrix gamma ray and shale properties were determined. The cleanest sand has a gamma ray of 25API while the wet clay has the following properties; Gamma ray 168.16API, Sonic 108.5µs/ft, Density 2.45g/cc and Neutron 0.36v/v (fig. 2). These values were matched with the Neutron -Density (fig. 2) and Neutron-Sonic (fig. 3) cross plots to see if it is consistent with the trends and were imputed in the parameter table (Table 4).

2.1.2 Porosity

An interactive matching of the core porosity against different porosities obtained from the Sonic, Density and Neutron logs (with or without shale correction) was made, the final porosity used was the Density derived porosity without shale correction because it is the more consistent with the core porosity data as indicated in the result plot (fig. 8).

2.1.3 Water Saturation

To estimate the water saturation, the Archie and Indonesia models were compared, the final water saturation model used was the Archie model because it gave the best result. To obtain the water saturation parameters, the formation resistivity factor measurements at ambient laboratory condition in nearby wells indicated a cementation factor (m) of 1.8, if Archie constant (a) is assumed to be 1.0. Also the regional formation water are known to be relatively fresh with salinity <10,000ppm NaCl equivalent. These values were used along with a temp value of 173.9°F to estimate the best fit line (water line) in the picket (resistivity vs porosity) plot (fig. 5). And the values imputed in the parameter table (Table 4). There is an effect of clay on the picket plot shown by the trend moving downwards.

2.1.4 Definition of Parameters Used

The parameters use to define the matrix properties are from Log responses to rock forming mineral table. Since the matrix is known to be quartz, the Density Neutron and Sonic values of quartz were imputed in the parameter table (Table4). The matrix properties and some other parameters used are illustrated below;

Matrix properties from basic log response to rock forming mineral

GR of 25 API for clean sand

Density 2.65g/cc

Neutron -0.02 v/v

Sonic 55.5µs/ft

Wet Clay properties from the GR X-plot (figure 2)

GR 168.16 API

Density 2.45g/cc

Neutron 0.36

Sonic 108.5 µs/ft

Pore fluid properties The impute values were based on that of fresh water

Density 1

Neutron 1

Sonic 189 µs/ft

Saturation parameters of nearby wells were used

Cementation facto (m) 1.8

Archies constant (a) 1.0

Saturation exponent (n) 1.8

Rw Temperature 173.9°F

Rw 0.7ohm-m

2.1.5 Net Reservoir pay

Three case scenario's were established (high, most likely and low) to determine the net reservoir. However, some sets of cut -off (clay volume, porosity and water saturation) were defined for all three cases. The porosity cut -off for the three cases was obtained from the core porosity vs horizontal permeability (kh) plot (fig. 7).The Vclay cut-off was used to define the reservoir, the porosity cut-off was used to define the permeable zones and the saturation cut-off was used to identify the hydrocarbon productive zone (net reservoir). The cut -off values for the clay volume and water saturation were obtained from the result plot (fig. 8).

3.0 Discussion of results

3.0.1 Lithology

The interval consists of medium - massive red claystones interbedded with sandstones. The claystones are generally reddish brown, dark red or occasionally dark brown, blocky to sub blocky, hard to very hard. These sandstones are mainly composed of consolidated quartz grains with no visible cement. They are medium to coarse grained and fair to poorly sorted with some interstitial clays described in some sands. Five cores were cut within the evaluated interval (Table 5). A conventional suit of wireline logs including gamma ray, Density, Neutron and Sonic logs were used to map out and define the lithological units (Table 6). Mud log gas shows were reported for three intervals (Table 7).

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Table 5 Cores cut from well SEATH-1

Core

Interval

Cut ft

Recovered ft

Recovery%

1

4851 - 4881

30

30

100

2

4881 - 4911

30

30

100

3

4911 - 4941

30

22

73

4

5195 -5225

30

30

100

5

5225 - 5255

30

27

90

Table 6 Lithology

Lithology

Interval

Claystone

4800 -4840ft

Sandstone

4840 -4910ft

Claystone interbedded with Sandstone

4910 -5000ft

Sandstone

5000 -5050ft

Claystone

5050 -5200ft

Sandstone

5200 -5240ft

Claystone

5240-5310ft

Sandstone Interbedde with claystone

5210-5440ft

Claystone

5340 -5490ft

Table 7 Mud Gas Show Intervals

MDRKB

(ft)

TVDKB

(ft)

BGG

Units

TG

Units

C1

ppm

C2

ppm

C3

ppm

IC4

ppm

NC4

ppm

C5

ppm

CO2

%

4990 -5045

4156-4194

15

70

8000

350

160

60

-

-

-

5200 -5235

4314 -4340

16

70

7000

1000

600

300

120

-

-

5310 -5343

4394 -4420

16

111

15000

1200

300

200

130

-

-

3.0.2 Zonation

The evaluated interval (4800 - 5490ft) was divided into 10 zones based on lithology and fluid content. This is represented on the log plot (fig.1) and on the parameter table (Table 3)

3.0.3 Reservoir properties - Zone averages

A suitable cut - off for the clay volume (Vclay), water saturation (Sw) and porosity were obtained from the result plot (fig. 8) and the core porosity vs horizontal permeability plot (fig. 7). These values were imputed into the zone average table (Table 8) to obtain the reservoir properties of the net reservoir and net pay. A cut -off values of 0.4 was established for the clay volume and 0.63 for water saturation. Three case scenarios; a high case (Table 9), a genera/most likely case(Table 8) and a low case( Low 10) were established based on the porosities obtained from the core porosity vs permeability plot and imputed into the zone average table to obtain the reservoir properties and net pay for the three scenarios. The difference observed from these three scenarios was not much. A permeability value of 1mD was used for all the cases this is the minimum cut-off for oil reservoirs.

The equivalent Hydrocarbon column (EPC) and Equivalent Pore Column (EHC) for the three cases show that the oil in the interval 4840 - 4910ft is the most prolific of all (Table 8).

3.0.3 Fluid and fluid contacts

The fluid and fluid contact were obtained from the log plot (fig. 8) and the pressure vs depth plot (fig. 6). On the log plot, oil zones were mapped out using the Density Sonic and Neutron logs, and the oil water contact (5350ft) was mapped out using the Array induction resistivity log alone. On the pressure vs depth plot, the oil and water zones were mapped out based on their pressure gradient. The position of the free water level 5364ft (5080ft TVDSS) was also mapped. From these results, 4 oil columns were established. Oil columns 1 and 2, have a gradient of 0.324psi/ft and is different from oil column 3 and 4 that have a gradient of 0.364psi/ft. This shows that Oil column 1and 2 are in communication, oil in column 3 and 4 are in communication but but are not in communication with those in column 1 and 2. The gradient of the Water is 0.429psi/ft. The densities of the two oil and water gradients were computed and they gave 0.75g/cc (column1 and 2), 0.84g/cc9column 3 and 4) and 0.99g/cc (water).

4.0 Summary and conclusion

The depth interval for the petrophysical evaluation of well SEATH-1 was 4800-5490ft. The intervals consist of interbedded claystone and sandstone units. From the evaluation of the available data, the following were observed.

Four hydrocarbon columns were delineated, that should be divided into two different units during production because of their pressure gradients.

From the log plot and the pressure depth plot, the oil water contact is at 5350ft while the free water level is at 5364ft this is due to threshold capillary effect and it is commonly encountered in poor quality reservoirs.

From the drill stem test result it was discovered that the permeability of the reservoirs are very good (176 and1070mD) with good porosity as shown in the core porosity vs horizontal permeability plot, high hydrocarbon saturation and good pay thicknesses. Well SEATH-1 can be said to be a good prospect, I will recommend that management should develop the prospect.

4.1 Recommendations

I will recommend that a drill stem test be carried out in the oil column at interval 4830-4900 since it is the most prolific from the evaluation carried out.

A special Core Analysis (SCAL) should be carried out on the core to measure the rock properties such as porosity at overburden pressure, permeability at overburden pressure, formation resistivity factor (FRF), Resistivity index (RI), Resistivity index at overburden pressure, capillary pressure, relative permeability and cation exchange capacity (CEC). Data from a nearby well to estimate for the water saturation could affect the result because salinity is known to vary within sands in the area.

The oil column in 1 and 2 should be produced together, while that in column 3 and 4 should be produced together but differently from that in column 1 and 2 because they have different pressure gradient and hence different densities.

I will recommend the fracturing of wells should be incorporated into the development plan to enhance the optimal production.