Fluid Contacts: Methods For Determining

Methods for determining

fluid contacts

By

Abbas Radhi Abbas E-mail : [email protected]

Methods for determining fluid contacts Methods for determining initial fluid contacts are listed in Table 1 and are discussed by Bradley.[1] These include fluid sampling methods, saturation estimation from wireline logs, estimation from conventional and sidewall cores, and pressure methods. Once initial fluid contact elevations in control wells are determined, the contacts in other parts of the reservoir can be estimated. Initial fluid contacts within most reservoirs having a high degree of continuity are almost horizontal, so the reservoir fluid contact elevations are those of the control wells

Table 1 Method for determining fluid contacts within a well

Method

Description

Advantages

Limitations

Rarely closely spaced, so contacts must be interpolated Fluid sampling: production Directly determines tests, drill stem

fluid contacts by

tests, Repeat

measuring

formation

recovered fluids

Direct measure of Problems with filtrate recovery on DST and RFT fluid contact

tester(RFT) tests

Coning, degassing, etc. may lead to anomalous recoveries

Estimates fluid

Saturation

contacts from

Low cost

changes in fluid

Accurate in

saturations or

simple lithologies

mobility with depth

determination: well

Saturation must be calibrated to production

logs Unreliable in Rapid High

complex

resolution

lithologies or low resistivity sands

Saturation

Estimates fluid

Saturation

Saturation measurements may not be accurate

determination: core

contacts from

estimates

analyses

changes in fluid

forcomplex

saturation with

lithologies

depth

Usually not Saturation can be

continuously

related to petro-

cored, so

physical properties saturation profile is not as complete

Imprecise; data usually require correction Estimates free Pressure profiles:

water surfacefrom

[[Repeat formation

inflections in

tester|RFT tests

pressure versus

Little affected by

Only useful for thick hydrocarbon columns

lithology or coning

depth curve

Most reliable for gas contacts Requires many pressure measurements for profile Requires accurate pressures

Imprecise; data usually require significant correction Pressure profiles: reservoir tests production tests drill stem tests

Only useful for thick hydrocarbon columns

Estimates free water surfacefrom

Makes use of

pressures and fluid widely available density measurements

pressure data

Most reliable for gas contacts Requires pressure tests from both fluid zones and assumed or measured fluid densities to estimate contact Requires accurate pressures

Figure 1 Contact definitions and relationship of contacts in a pool (right) to reservoir capillary pressure and fluid production curves (left). The free water surface is the highest elevation with the same oil and water pressure (zero capillary pressure). The oil-water contact corresponds to the displacement pressure (DP) on the capillary pressure curve. The transition zone is the interval with co-production of water and hydrocarbons. The fraction of co-produced water is shown by the dashed line on the left. The gas-oil contact is controlled by the volume of gas in the trap, not the capillary properties.

Figure 2 Geometries of fluid contacts. (a) Horizontal contacts indicative of hydrostatic conditions in homogeneous reservoir rock. (b) Tilted, flat contacts resulting from hydrodynamic conditions. (c) Contact elevation is constant for each lithology type, but pool contact is irregular due to reservoir heterogeneity. (d) Irregular contacts due to semipermeable barrier in an otherwise homogeneous reservoir.

Figure 3 Example of calculating hydrodynamic fluid contacts from pressure data. Pressure elevations are shown by arrows. Calculated fluid contacts are shown by thin lines.

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