PTRL 4010 Final Year Thesis

Drillstem Test, DST Analysis

Ahmad Zikri B Nor Azlan

z3270484Date of submission: 2 April 2012

TABLE OF CONTENT

Topic Page

List of Figures 2List of Tables 3Abstract 4

1.0

Introduction 5

2.0

Pressure versus Time for the Whole Test Period and Validity Check

6

3.0

Pressure versus Time Plot for Main Build-Up Period 10

4.0

Average Production Rate 13

5.0

Production Time 16

6.0

Horner Semi-Log Plot Analysis 19

19

7.0

Actual Sand Thickness for Producing Interval 21

8.0

Conclusions 22

23

References 25

LIST OF FIGURES

Figures Page

Figure 1.

Downhole DST tool string 9

Figure 2.

Pressure-Time plot for DST 10

Figure 3.

Pressure versus time for the whole test period 11

Figure 4.

Plot of pressure versus time for initial cycle 12

Figure 5.

Plot of pressure versus time for main cycle 13

Figure 6.

Plot of pressure versus time for unloading cycle 14

Figure 7.

Plot of pressure versus time for surge cycle 17

Figure 8.

Plot of pressure versus time for main build-up test 18

Figure 9.

Production time for main cycle 23

Figure 10.Extrapolation to the y-axis to determine the initial reservoir pressure

Figure 11.

Horner Semi-Log plot with the slope m1

Figure 12.

Horner Semi-Log plot with the slope m2

Figure 13.

Actual sand thickness based from well logs

LIST OF TABLES

Tables Page

Table 1.

Oil Rate during the main flow period 15

Table 2.

Data needed for Horner Semi-Log plot analysis (SCOPE4)

19

Table 3.

The parameters obtained from slope m1 22

Table 3.

The parameters obtained from slope m2 22

Abstract

In this report, drillstem test, DST is conducted in order to determine the Original Oil in Place (OOIP) in Skua 4 field. This program is usually run during the exploration phase with the main purpose of gaining information on reservoir geometry, establishing well productivity and obtaining representative fluid samples. Inside this report, analysis of Horner semi-log plot is described step-by-step to determine the formation permeability, skin factor and initial reservoir pressure. Besides that, the presence of shale is also determined in using the gamma logs to calculate the shale thickness around perforation area.

The body of the report contains pressure data versus time graph for the entire test period to check its validity on whether the test is accurate. Then, from the graph, 4 sections are identified and are showed in larger scale to detect any anomalies. For Horner analysis, pressure data on main build-up period is focused more. Next, the production time and average flow rate are extracted and calculated from the Well Completion Report. Then, using Mathcad, Horner semi-log plot is evaluated and associate parameters are calculated. Lastly, actual sand thickness is determined based from gamma log due to presence of shale.

Based on our calculation, Permeability is between 500 to 800 md, skin factor is between 2.5 to 3.9 and the initial reservoir pressure lies between 3334 to 333 psia. Although the result is not the same as the Well Completion Report, it suggests that the formation is good permeability and had damaged.

Therefore, DST analysis is proven to be beneficial in helping to understand the reservoir behavior. However, there are some limitation and more investigation needed to reduce uncertainty.

Introduction

In determining the Original Oil In Place OOIP in the Skua Field, Skua -4 was drilled in August 1988 as appraisal well. The well has found a 50 m gross hydrocarbon column with approximately 5 m net gas pay and 19 m net oil pay. The 7 m interval in the oil bearing sand was perforated and a production test was performed. (SCOPE 4)

Production test in another word can be called as drillstem test (DST). DST typically performed on exploration or appraisal well in order to determining whether a well has found a commercial hydrocarbon reservoir. In addition, DST provides a temporary completion that allows pressure testing of a part of a formation.

DST can provide sample of reservoir fluid for further analysis. DST also gives indication of well production rate, which is important whether to continue with the appraisal well. High production rate is highly favorable. Besides that, DST is able to provide static and flowing reservoir pressures as well as gives short pressure transient test (pressure buildup). Furthermore, DST data interpretations are able to estimate the formation permeability, formation damage indication and initial reservoir pressure. The calculation and correlation will be described in details in this report. However, the value calculated may be differ with well log data.

Figure 1: Downhole DST tool string

To run the drillstem test, drillstring is lowered to the zone to be tested with a special DST tool attached. Once at the bottom, the packer is set to seal the bottom to isolate the formation from the mud column annulus. The low pressure inside the DST tool allows formation fluid to flow into the drillpipe and continuously records the pressure during the test. Figure 2 below shows a typical pressure profile of a DST:

Figure 2: Pressure-time plot of a DST

The graph above is a schematic DST pressure chart for a two-cycle test. The first cycle test includes the initial flow and buildup periods, while the second cycle includes the flow and final buildup periods.

Mentioning the pressure profile, during initial part (1), shows that a drillstring is being run into the hole that indicates by increased in pressure. The initial hydrostatic mud pressure at the depth of interest is represented as Pihm. Then, the packer is set leading to decrease in pressure to Pifl, initial flow period. The initial flow period in (2) follows as a packer being released to allow formation fluid to flow into the drillpipe indicating a slight increase in pressure. Final flowing pressure, Pff1 at (3) shows an increasing pressure to formation pressure prior to the start of shut-in period and eventually reaches to the initial shut-in pressure, P isi. Next, final cycle of flow and shut-in period takes place and showed in (4) and (5). The pressure increases with the same pattern of initial cycle. However, not as high as the initial cycle pressure at shut-in period. Finally, hydrostatic mud pressure, Pfhm is obtained and DST tool is unpacking and is pulled out.

For a standard DST, the initial flow period is usually short approximately 5 to 10 minutes. The reason is to release the high hydrostatic mud pressure. The initial shut-in however needs to be sufficiently long to allow the measured pressure to approach stabilized formation pressure and normally is 1 hour. The second flow also need to be long enough in order to achieve stabilization. For the final shut-in period, it depends on the test behavior during the final flow period.

DST for Skua-4 aims to gain information on reservoir geometry, establish the productivity of the well and obtain representative fluid samples. After

completion of the main test, a short surge test was conducted in an attempt to improve the productivity of the well.

Generally, the DST of Skua-4 consists of four test cycles of different periods. The test cycles are:

The initial flow (4.3 minutes) and the initial build-up (1.1 hour) The main flow (25.7 hours) and the main build-up (26.5 hours) The unloading flow (0.3 hours) and the unloading build-up (0.6

hours) The surge flow (4.5 hours) and the surge build-up (2.3 hours)

The report consist into 6 parts which consists of:

Plot of pressure versus time for the whole test period and test validity check

Pressure versus time plot of the main build-up period Production time determination Estimate average flow rate of the main flow period Sand thickness determination Horner semi-log analysis

Pressure versus Time for the Whole Test Period and Validity Check

Before proceed with determination of associated parameters such as permeability, skin factor and initial reservoir pressure from the analysis of Horner semi-log plot, a quality check is measured to detect any anomalies during the test. The anomalies are checked by looking into the pressure data as a function of time for the entire test period. Using data from SCOPE4 a figure below is plotted (Pressure versus time).

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Figure 3: Pressure versus time for the whole test period

The graph above is divided into 4 cycles, which are initial cycle, main cycle, unloading cycle and surge cycle. The longest cycle can clearly seen to be the main cycle. Figure 4, 5, 6, 7 will show each section in details.

35.16 35.18 35.20 35.22 35.24 35.26 35.28 35.30 35.32 35.343180320032203240326032803300332033403360

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Figure 4: Plot of pressure versus time for initial cycle

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Figure 5: Plot of pressure versus time for the main cycle

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Figure 6: Plot of pressure versus time for the unloading cycle

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Figure 7: Plot of pressure versus time for the surge cycle

From the SCOPE4 report, there was a problem with MUST tool that restrict the flow between the gauge bundle carriers and the top of the MUST creating an increase in pressure different. The problem was detected by the pressure data from surface readout (SRO) gauge that recorded a significant different when compared with CF015 data during the main flow. This restriction causes the small different of pressure curve compare with ideal curve. In some of the cycle, pressures increase is noticeable during flow period.

During the testing, somehow the data was affected by the “tidal effects”. The correction was made to pressure data of Skua-2 and Skua-5. However, in Skua-4 there was no correction applied, as it is not too significant.

Besides that, the surge cycle does not give a complete data and is suspected to be missing from the well completion report.

Nevertheless, the mechanical problem with MUST tool does not dominantly affect the shape of main build-up curve and Horner semi-plot is constructed and analyze below.

Pressure versus Time Plot for Main Build-Up Period

In constructing a Horner semi-log plot analysis, the pressure versus time is drawn from Mathcad and shows below:

Figure 8: Plot Pressure versus Time for the main build-up test

A not smooth shape of pressure build-up graph above is contributed with the problem of MUST tool that discussed in previous section.

Average Flow Rate

An average value of flow rate needs to be determined in order to create a Horner semi-log plot graph. Under typical oil production, the rate will decrease with time as the bottom hole pressure increase and liquid head builds up with production. However, the change is neglected and average rate is used. Table below shows a recorded flow rate of period of 22 hours of main flow period.

Table 1: Oil Rate during Main Flow Period (SCOPE-4)

By taking average, the average flow rate is 586 STB/day.

Production Time

The production time must be obtained from the main cycle for further analysis in creating Horner semi-log plot. From the Well Completion Report, the production time is 25.7 hours. The production also can be determined from the pressure time curve as shown below:

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25.7 hours

Figure 9: Production time from the main cycle

Horner Semi-Log Plot Analysis

The Horner Semi-Log plot is used generally to estimate the formation permeability, skin factor and initial reservoir pressure based on assumption that the reservoir is in infinite acting and has no wellbore storage effects.

The Horner equation is:

The graph (pi – pws) versus log [{tp+t)t] create a straight line slope m,

After constructing a Horner graph, m can be determined. Permeability canbe calculated if the formation thickness, h is known giving the equation:

The skin factor on the other hand is determined based from the equation below:

Positive value shows the formation is damaged and negative values points to a stimulated formation.

Finally, the initial reservoir pressure can be obtained by extrapolating the Horner pressure build-up test semi-log plot to the y-axis. This is the generally term used as infinite shut-in, the well will eventually build up to its initial pressure. The interpolation is shown in the figure below:

Figure 10: Extrapolation to the y-axis to determine the initial reservoir pressure.

By using Mathcad and data from the Well Completion Report, Horner semi-log plot analysis is carried out. The data needed for analysis is extracted from the report and compiled in table below:

Parameters ValuesCompressibility, c 0.198 x 10-4

Viscosity, 0.3 cpPorosity, 0.24Formation thickness, h 19.7 ftFormation volume factor, B 1.57 RB/STBWell radius, rw 0.354 ftAverage flow rate, q 586 STB/dayProduction time, tp 25.7 hoursPressure at shut-in, pwf 3299.774psiaTable 2: Data needed for the Horner Semi-Log plot analysis. (SCOPE4)

The Horner Semi-log is drawn using Mathcad using the data from the main build-up period. For this case, due to non-linear graph created, two graphs are constructed as we take two different slopes to give range of values for permeability, skin factor and initial reservoir. The graphs are illustrated below:

Figure 11: Horner Semi-Log plot with slope m1

For slope m1, the parameters are in the table below:

Permeability 741.4 mdSkin Factor 3.9Initial Reservoir Pressure 3334 psia

Table 3: The parameters obtained from slope m1

Figure 12: Horner Semi-Log plot at slope m2

For slope m2, the parameters are in the table below:

Permeability 597.2 mdSkin Factor 2.5Initial Reservoir Pressure 3337 psiaTable 4: The parameters obtained from slope m2

In general, the range of permeability is between 600 to 800 md, the skin factor between 2.5 and 3.9. The initial reservoir pressure is estimated to be between 3334 and 3337 psia. In comparison with Well Completion Report, Horner anlaysis gives permeability between 900 and 1100m, skin factor between 4-7 and initial reservoir pressure of 3337.5 psia. The different in these values are due to different pressure data point to construct associated slope. Even though different values of parameters obtained, the values calculated in this report is still relevant showing that the formation have a good permeability and the formation is damaged as a result of positive skin factor.

Actual Sand Thickness for Producing Interval

Based from well completion report, perforation is conducted between the interval of 2318 m and 2325 m in the oil-bearing sand to perform DST. However, DST cannot be performed, as there is existence of shale has not been considered into account. The actual sand thickness needs to be determined from well logs.

Gamma ray log is used to identify the sand and shale layers in the reservoir. This is done through Larionov equation for older rocks, which uses data from the gamma ray log to determine shale volume as a fraction. Cut-off shale volume of 40% is assumed and the perforated interval can be separated into producing and non-producing ones.

Before using Larionov equation, radioactive index, IRA is calculated using formula below:

Maximum gamma-ray reading shows a presence of shale while minimum reading show clean sand. Then, Larionov equation for older rocks is applied for determination of shale volume, Vsh:

The interpretation is illustrated in Figure 14, The figure on the left shows a plot of Vsh against depth with cut-off indicator. As a result, a shale layer thickness to be 1 m givinh 6 m of actual sand thickness.

Figure 13: Actual sand thickness based from well logs

Conclusion

As a conclusion, DST has been extremely convenient tools in formation evaluation tool. It takes sample fluid for further investigation and also collects pressure data to be analyzed using Horner semi-log plot to evaluate more about formation properties. It also used to gain more information on reservoir geometry and establish the productivity of the well.

In this report, the parameters of interest are permeability, skin factor and initial reservoir pressure. Based from parameters show in this report and although the values are different compare with Skua-4 report, it suggests that the formation has good permeability and had been damage.

Despite obtaining good results in DST, further analysis using analytical technique cannot be undertaken because of three opposing influences on the buildup:

1. A nearby gas cap which increase the apparent transmissibility2. Nearby truncation of the sand which will decrease transmissibility3. Communication with other sands further away from the well

Therefore, a further investigation needs to be done to improve understanding and reduce the uncertainty within the reservoir. For instance, a reservoir simulation of the test is planned to fully interpret the pressure data.

References

1.Pinczewski, W.V, 2011, Well Testing Course Notes, UNSW

2.Salisch, H, 2011, Introduction to Petrophysics Course Notes, UNSW

3.Well Completion Report for Skua-4 (SCOPE 4)

4.Earlougher, Advances in well test analysis, SPE Monograph Volume , 1977