Pan System Exercise Workflow Biology Essay

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In this exercise, the type of test conducted was a pressure build up test which is the most widely used technique in the form of transient well testing. Pressure build-up testing entails shutting in a producing well and recording the closed-in bottom-hole pressure as a function of time. The most common and simplest analysis techniques require that the well produce at a constant rate, either from start-up or long enough to establish a stabilised pressure distribution before shut-in. From the data, we can see that the well had been producing for 10,000 hours with a production rate of 5681 STB/day so has met the required conditions. The reservoir is a fluvial reservoir, which is a very important hydrocarbon reservoir worldwide due to its fluvial depositional characteristics which give rise to the complex petro physical properties, spatial distribution patterns, internal heterogeneities and complex reservoir geometries. Therefore, well testing because it measures the dynamic response of the reservoir is a very important tool for investigating these properties in fluvial reservoir systems. The well orientation is vertical. The general description of the reservoir are summarised in Table 1 below.

General Description

Test type

Pressure build up

Production history

Producing time

Geology

Fluvial reservoir

Testing time (hrs)

10,000

Table 1

Reservoir Description

Fluid type

Single-phase Oil

Well orientation

Vertical

Number of wells

1

Number of layers

1

Layer Parameters Data

Layer 1

Formation thickness (ft)

255.0000

Average formation porosity

0.1310

Water saturation

0.0000

Gas saturation

0.0000

Formation compressibility (psi-1)

0.000000

Total system compressibility (psi-1)

1.4400e-5

Layer pressure (psia)

5429.006588

Temperature (deg F)

0.000000

Well Parameters Data

Well 1

Well radius (ft)

0.2540

Fluid Parameters Data

Layer 1

Oil viscosity (cp)

0.660

Oil formation volume factor (RB/STB)

1.567

Total system compressibility (psi-1)

1.4400e-5

Rate Change Data

Time (Hours)

Pressure (Psia)

Rate (STB/day)

-9994.55762

0.0000

0.0000

5.44200

4686.0000

5681.0000

74.55000

4798.9199

0.0000

2. WELL TEST ANALYSIS

DIAGNOSTIC

In many cases the pressure response from a well test can be divided into three distinct periods when presented on a semi log plot as illustrated in Figure 1 for constant rate drawdown. These are termed respectively, Early time region (ETR), Middle time region (MTR) and Late time region (LTR)

Figure 1: Flow regimes on a Semi log graph

Early time region (ETR) is the period of wellbore storage dominated behaviour (pD = tD/CD) and the transition period when wellbore storage and the formation both influence the response is known as the early time region (ETR). Type curve matching is used in the analysis of the early time region, especially when it is associated with wellbore storage.

When it exists, the middle time region is associated with infinite acting, radial flow behaviour and has the characteristic semilog slope of - µq/4Pkh. The estimation of permeability from well testing depends crucially on the correct identification of the MTR.

The late time region occurs when the bottom-hole pressure response of the well is influenced by the boundaries of the system. These may be no-flow boundaries arising from sealing faults or constant pressure upper or lower boundaries due to a gas cap or aquifer.

One of the tasks required for this exercise was to identify the flow regimes on the diagnostic (log-log) plot in terms of the features of the early time region (ETR), middle time region (MTR) and late time region (LTR).

In the Pansystem software, after loading the file "DST.tpr" from the directory, to define the three times, Click on the top bar and then click on the log log icon. To define the first time (ETR) which is the wellbore storage, select the unit slope line icon and click "Ok", then move the straight line to match wellbore storage and click on the "FR" (flow regime) icon in order to define the start and end point of wellbore storage.

To define the second time (MTR) which is the radial flow, select the zero slope line icon and click "OK", then move the straight line to match radial flow and click on the "FR" icon to define the start point and end point of radial flow.

To define the third time which is the late time boundary condition, select the character slope line icon and click "OK", then move the straight line to match radial flow and click on the "FR" icon to define the start and end point of the boundary response.

Type curve matching was used to help with the model selection. Using the Pan System software, the "TC" (Type curve) icon was selected and then matched using the "M" icon. The type curve was then used to match well bore storage, and then matched again by moving the type curve to match the radial flow and boundary condition. The resulting graph illustrated in Figure 2 shows that the flow is radial homogeneous, with parallel faults and classic wellbore storage. The wellbore storage coefficient is generated automatically by the software but we know that it can be derived from CD=bbl/psi

Figure 2: Type Curve Plot

SPECIALISED ANALYSIS

Radial flow analysis

In the type curve matching process three unknown parameters are identified, viz. permeability, k, skin factor, S, and the wellbore storage constant, Cs, given by:

Cs= [CD]M2πΦcthrw2

Once the match has been made it is now easier to observe if any data points lie on the semi log straight line, i.e. if they fall on one of the asymptotic lines of pD(0, S, tD). If middle time region exists and in this exercise it does as illustrated in the graph below, this data can be analysed on a semilog drawdown plot. The period in which the propagating pressure disturbance has not yet encountered any boundaries is known as the infinite-acting or transient flow regime. It is this data which yields a straight line on the semilog plot, i.e. the pressure is varying with the log of time, and it is also referred to as the middle time region (MTR).

The diagnostic role of identifying which data points are suitable for semilog analysis is also a very important application of type curve analysis. The best estimate of permeability is derived directly from the constant value of the slope and intercept in the middle time region of the semilog graph. However important properties of heterogeneous systems can be deduced from any changes in the slope of the semilog plot; for example the existence of a fault causes the slope to double at late time and the presence of a constant pressure boundary makes the slope zero at late time.

The graph in figure 3 below illustrates that the flow is radial homogeneous, with parallel faults with classic wellbore storage. The graph is analyzed and plotted on a semi-log plot.

Figure 3: Radial Flow Plot

Linear flow analysis

After the MTR period analysis, the relevant parameters are stored (k, S) and the linear flow plot can give estimates of the geometry of the system, L1, L2 and W. Once the pressure behaviour of the well is influenced by boundaries the late time region (LTR) is entered and in a closed system produced at constant rate a state of semi-steady-state (sss) depletion is eventually attained. In this flow regime the bottom-hole flowing pressure, pwf, varies linearly with time as shown in Figure 4 below.

The figure below illustrates that the flow is radial homogeneous, with parallel faults with classic wellbore storage. The graph is plotted on a square root of time plot

Figure 4: Linear Flow Plot

Sketch of boundaries relative to the well

Simulation/flow regime history matching

The auto matching method matches the field data with theoretical reservoir models using a constrained, nonlinear, least-squares regression technique coupled with numerical Laplace inversion of pressure-drawdown equations. Pressure gradients are computed by forward finite-difference approximations. Hence, reservoir models whose pressure gradients are difficult to obtain analytically can be readily included. Only equations for drawdown type curves of reservoir models are needed. The method reduces the time required to perform well test analysis and minimizes the subjectivity of interpretation. It is used as the basis for the inverse problem of parameter estimation, i.e. determining kh and S by matching the observed pressure transient response to that predicted by the model.

By utilising the special property of log-log type curves, which preserve the shape between dimensionless (theoretical) responses and actual data plotted on a compatible scale, it is possible to determine the most appropriate fault model by a matching process. A log-log derivative type curve for fault analysis is simply the graphs of p′D versus tD/L2D for the various elementary cases presented simultaneously in log-log form. This will be referred to as a tD/L2D or fault system type curve; it is used to analyse the MTR and LTR regions when the late transient behaviour is due to sealing faults. The figure below illustrates that the flow is radial homogeneous, with parallel faults with classic wellbore storage. The graph is plotted on a log-log plot. This is a flow regime match analysis plot.

Figure 5: Log-Log Plot

Figure 6: Test Overview

3. WELL TEST INTERPRETATION

From the discussions above, we know that the Early time region (ETR) is the period of wellbore storage dominated behaviour (pD = tD/CD) and the transition period when wellbore storage and the formation both influence the response and that type curve matching is used in the analysis of the early time region, especially when it is associated with wellbore storage. We also know that the middle time region is associated with infinite acting, radial flow behaviour and has the characteristic semilog slope of - µq/4Pkh and that the estimation of permeability from well testing depends crucially on the correct identification of the MTR. Finally, we know that the late time region occurs when the bottom-hole pressure response of the well is influenced by the boundaries of the system. The difficulty in obtaining a reliable description stems from the large scale and heterogeneous nature of the reservoir and the very limited number of points, i.e. the wells, at which observations can be made, therefore this leads to uncertainties in the test analysis results.

Therefore the importance of multidisciplinary integration in resolving this uncertainty cannot be underestimated.

There are several ways by which it is possible to gain information about the reservoir characteristics other than transient pressure testing of wells and these include; seismic and associated geological studies, information obtained during the well drilling programme which includes, the analysis of cutting and cores, and interpretation of various logs, wireline formation testing and finally the analysis of reservoir performance e.g. through history matching using a simulator. It can be seen that the reservoir is a fluvial reservoir, which is a very important hydrocarbon reservoir worldwide due to its fluvial depositional characteristics which give rise to the complex petro physical properties, spatial distribution patterns, internal heterogeneities and complex reservoir geometries. Therefore, well testing because it measures the dynamic response of the reservoir is a very important tool for investigating these properties in fluvial reservoir systems.

4. SUMMARY AND CONCLUSION

In conclusion, based on the results gotten from the diagnostics of radial and linear flow, the skin factor and permeability were obtained. The table of results from the various plots are tabulated and summarised below.

Diagnostic results tables

Local Results

Value

Permeability (md)

494.48953

Permeability-thickness (md.ft)

1.2609e5

Wellbore storage coefficient (bbl/psi)

0.047423

Dimensionless wellbore storage

1365.491134

Skin factor

0.995535

Distance to boundary (ft)

568.113575

Stage 1

Stage 2

Match point - X

-3.074988

0.488781

Match point - Y

-0.818175

-0.818175

Curve Number

7.000000

3.000000

Curve Value

10000.000000

2.000000

Radial flow analysis tables

Local Results

Value

Permeability (md)

615.48059

Permeability-thickness (md.ft)

1.5695e5

Extrapolated pressure (psia)

4775.783836

Radius of investigation (ft)

5358.913708

Flow efficiency

0.792982

dP skin (constant rate) (psi)

16.930730

Skin factor

3.203006

Line Details

Line type

Radial flow

Slope

-6.0856

Intercept

4775.78

Coefficient of determination

0.996401

Radial flow

Extrapolated pressure (psia)

4775.783836

Pressure at dt = 1 hour (psia)

4751.441163

Number of Intersections

0

Linear flow analysis Tables

Local Results

Value

Channel width (ft)

989.055264

Distance to nearest fault (ft)

437.710705

Convergence skin

6.445668

Permeability (md)

615.48059

Skin factor

3.203006

Extrapolated pressure (psia)

5429.006588

Line Details

Line type

Reservoir linear flow

Slope

-6.84013

Intercept

5429.01

Coefficient of determination

0.999423

Reservoir linear flow

Extrapolated pressure (psia)

5429.006588

Number of Intersections

0

Simulation/flow regime history matching tables

Local Results

Value

Wellbore storage coefficient (bbl/psi)

0.132363

Dimensionless wellbore storage

3812.951625

Permeability (md)

508.151434

Permeability-thickness (md.ft)

1.2958e5

Skin factor

1.530139

Channel width (ft)

1105.197869

Line Details

Line type

Wellbore storage

Slope

1

Intercept

2802.32

Coefficient of determination

Not used

Line type

Radial flow

Slope

0

Intercept

3.20117

Coefficient of Determination

Not used

Line type

Reservoir linear flow

Slope

0.5

Intercept

3.368

Coefficient of Determination

Not Used

Line type

Free model line

Slope

0

Intercept

11.875

Coefficient of Determination

Not used

Number of Intersections

0

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