Determination Of Reservoir Characteristics And Parameters Biology Essay

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Well test is the one of the most widespread instrument of the petroleum engineers for determination of reservoir characteristics and parameters. It consists of different tests. The build-up and drawdown tests are the most common and useful.

In the given case the pressure build-up test is considered. The procedure of this test required to shut-in the well for certain time after flowing with constant rate. In our case well was working during 100000 hours with constant rate equals to 581 bbls/day. The next step is determination of the bottom hole pressure which will be a function of time. The build up analysis was carried out for 69.1 hours and the initial data are represented in table 1.

Table 1. Initial data

Fluid type

Single phase oil

Orientation of the well

vertical

Number of wells

1

Number of layers

1

Formation thickness (ft)

259.00

Average formation porosity

0.13

Total system compressibility(psi-1)

1.4500e-5

Layer pressure (psia)

4780.80

Well radius (ft)

0.259

Oil viscosity (cp)

1.200

Oil formation volume factor (RB/STB)

1.420

Figure 1

Fluid type

Single phase oil

Orientation of the well

vertical

Number of wells

1

Number of layers

1

Formation thickness (ft)

259.00

Average formation porosity

0.13

Total system compressibility(psi-1)

1.4500e-5

Layer pressure (psia)

4780.80

Well radius (ft)

0.259

Oil viscosity (cp)

1.200

Oil formation volume factor (RB/STB)

1.420

Figure 1 shows distribution of pressure and rate changes. It might be possible to consider that our well developed fluvial reservoir and this is useful information for further analysis of data from build-up test.

Well Test Analysis

The (log-log diagnostic) plot of derivative pressure and Agarval time coordinates is basic tool to make a diagnosis of flow regimes. This plot is used to determine of flow regimes. Three regimes on log-log plot: early time region, middle time region, late time region are indicated.

Early time region

Early time region is considered to be a wellbore dominated period. At early time reservoir does not act, thus all flow is produced by the expansion of fluid in the wellbore. This phenomena is known as wellbore storage effect. Wellbore storage effect is described by wellbore storage coefficient Cs. (Figure 2)

Distinctive feature of wellbore storage observed on diagnostic plot is a unit slope straight line. At the end of early time region reservoir starts affect the flow. This is a transition period between ETR and MTR. For a well with positive skin a "hump" can be observed on log/log plot. In the majority of tests early time region data are missed (convergence of pressure and pressure derivative on log/log plot), therefore it is impossible to derive the exact value of Cs. However, Cs can be performed using type curve matching, though this procedure has a number of limitations

Middle time region

Middle time region is known as reservoir dominated period. It is characterized by infinite acting reservoir behavior. Thus, middle time region is presented by radial flow. Radial flow is commonly transient flow, and pressure changes linearly with ln(t). Distinctive "fingerprint" of radial flow is zero slope straight line (also reffered to as derivative plateau) on the diagnostic plot. Data obtained from middle time region are important, since it is used in determination well productivity: average permeability and total skin factor (mechanical conditions at the bottomhole) and also reservoir pressure. Semilog plot is applicable for radial flow analysis. Since it is a build up, production history must be accounted - using Horner's time (Figure 2).

tp - production time delta t - build up time

Late time region

Late time region reflects the effect of external boundaries on the pressure behavior, deviating the flow from radial. There are a number of well known models of boundaries, which have particular features on diagnostic plot. When pressure propagation reaches the last boundary, flow becomes semi-steady-state. In semi-steady state regime pressure changes linearly with time (Figure 2).

Type curve matching

Type curve matching is used for model selection (Figure 3). If ETR data are missed, it is the only way to estimate Cs. For wells with ideal wellbore storage, shape of pressure derivative and ∆P depends only on Cs and skin, and does not depend on other reservoir properties. Therefore, having a set of such dimensionless type curves, one can choose curve which fits best the given curves. However there are limitations of this method. This approach works only for wells with ideal wellbore storage. In light of the fact, type curve is used as estimation of Cs and not an exact value. Table 2 present data type curve matching.

Specialised Analysis

Radial flow analysis

Radial flow plot is a plot of pressure versus log Horner time (Semi-log plot present to Figure 4). Permeability can be derived from the slope of the straight line part of the plot by the following equation:

.

Skin factor is calculated as follows:

P* is extrapolated pressure. One to have been lasted for 10000 hours while buld-up have been lasted only 69.1 hours. Radial flow analysis results are presented in table 3.

Linear flow analysis

The half slope of straight line in late time region indicates linear flow (Linear flow plot present to Figure 5). Linear flow plot is a plot of pressure versus square root of time. This plot is used for boundaries determination. Linear flow is an indication of a channel formed by two parallel impermeable faults. Channel width and distance to the nearest boundary are executed from the plot. Whereas channel width is precisely determined, well position is more variable, raising additional uncertainty in further interpretation - additional data required (wireline, seismic). Data from linear flow plot present to table 4.

Figure 6. Well and boundaries location

Simulation / Auto Matching

Auto matching is a procedure of comparing of reservoir parameters (Auto matching present to Figure 7,8,9,10). Values of K, S obtained from previous analysis are used as primary input data for the model. Computer than tunes this data in order to match given data with the model using linear regression and other sophisticated algorithms. Process is iterative, when deviation criteria are satisfied, matching stops. So, automatch gives the most reliable values of K and S. However, Human control is required, since best fit can be unrealistic (negative skin for untreated well)

Quick match is building pressure change curves using current values of reservoir parameters. It is used as express test of model applicability. Data history matching present to table 5.

Well Test Interpretation

Well test analysis is sometimes the only method obtain average reservoir permeability and wellbore mechanical condition (skin factor). Therefore these data can be used in further reservoir modelling.

Well test analysis deals with inverse solution of Darcys low, therefore several different solution provide the same result. In order to minimize uncertainty, well test data should be correlated with wireline logging, seismic surveys and core data. Inappropriate model selection can result to permeability and skin overestimation (using infinite acting model for a bounded reservoir may show negative skin value).

One of the main problem of WTA is interpretation of pressure and pressure derivative curves of late time region. -----------------------

Summary and Conclusions

Results of well test analysis are presented in Table 5. Results of history matching are more precise and can be used in further reservoir simulation.

Table 5. Result of well test analysis

Diagnostic plot

Type curve plot

Radial flow plot

Linear flow plot

Auto flow

Permeability, k, (mD)

93

104

102

-

119

Skin factor, S

3.5

5

4

-

6

Wellbore storage coefficient, Cs , (bbl/psi)

-

0.0036

-

-

0.0061

Width of channel, W, ft

327

296

-

315

289

Distance to boundary L1, ft

-

148

-

101

119

Distance to boundary L2, ft

-

-

-

-

170

Figure 2. Log-log plot

ETR

MTR

LTR

Figure 3. Type curve matching

Table 2 data type curve matching

Parameters

Value

Permeability (md), k

104

Permeability-thickness (md.ft), kh

26914

Wellbore storage coefficient, Cs , (bbl/psi)

4788

Distance to boundary L, ft

148

Skin factor, S

5

Figure 4. Semi-log plot

Table 3. data from semi-log plot

Parameters

Value

Permeability (md), k

102

Permeability-thickness (md.ft), kh

26361

Extrapolated pressure (psia),

4788

Flow Efficiency, FE

0.7526

Skin effect (constant rate) (psi),

23

Skin factor, S

4

Figure 5. Linear flow plot

Table 4 data linear flow plot

Parameters

Value

Width of channel, W, ft

315

Distance to boundary L1, ft

101

Skin factor, S

4

Permeability (md), k

101

Extrapolated pressure (psia),

4811

Figure 7. Flow regime match

Figure 8. Radial flow plot match

Table 6. data history matching

Parameters

Value

Permeability (md), k

119

Wellbore storage coefficient, Cs , (bbl/psi)

0.0061

Distance to boundary L1, ft

119

Distance to boundary L3, ft

170

Skin effect (constant rate) (psi),

28

Skin factor, S

6

Width of channel, W, ft

289

Figure 9. Linear flow plot match

Figure 10. Test overview match

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