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Interpreting data collected during a single well chemical tracer test

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Even with a properly designed single well chemical tracer (SWCT) test, interpreting the data requires judgment calls, and typically, simulation, to arrive at a final estimation of residual oil.

Overview of the area under study

Tomich et al.[1] report one of the earliest SWCT tests, which was performed on a Frio Sandstone reservoir on the Texas Gulf Coast. The results of this test are used here to demonstrate the details of SWCT test interpretation for an ideal situation.

The test well in the Tomich et al.[1] report was in a fault block that had been depleted for several years. Because of the natural water drive and high permeability of the sand, the formation was believed to be near true Sor. When the well was returned to production (gas lift), it produced 100% water at a rate of 1,000 BWPD.

On the basis of observed reservoir temperature (160°F) and brine salinity [100,000 ppm total dissolved solids (TDS)], ethyl acetate was chosen as the primary tracer. Formation oil and water samples were obtained for laboratory measurement of K at reservoir temperature conditions. The value of Ke measured for ethyl acetate was 6.5 at these conditions.

Data from the test

The test injection consisted of 1,000 bbl of formation water carrying ethyl acetate (13,000 ppm) and methyl alcohol (5,000 ppm), followed by a push bank of 1,000 bbl of formation water carrying methyl alcohol (5,000 ppm), injected over a period of two days. An eight-day shut-in period followed. During the production period, samples were collected regularly and analyzed on site using gas chromatography. The observed data are plotted as tracer concentration vs. produced volume in Fig. 1.

Estimating residual oil saturation

In ideal cases, when enough data have been gathered to define the tracer profiles, it is possible to use Eqs. 1 through 3 to approximate Sor in the field.




If product tracer B and unreacted ester A begin together in the formation, the produced volume when A arrives back at the well (QpA) is related to the produced volume when B arrives (QpB) by the formula


where QpA and QpB are in bbl.

This suggests that if on the same graph we plot normalized concentration of A vs. volume produced (Qp) and normalized concentration of B vs. Qp(1 + βA), the two curves should coincide. Because we do not know βA, this must be done by trial and error (i.e., βA is adjusted until the best possible match of the two profiles is found).

Fig. 2 demonstrates this procedure. Profiles from the SWCT test (Fig. 1) first were normalized by dividing each observed concentration by the peak value measured for that tracer. βA then was varied to obtain the plot shown. The best-fit value for βA was 0.97.

Using Eq. 3, the Sor is approximated as


Agreement is only fair over the entire curve in Fig. 2; still, this result is quite close to the final interpreted result, obtained as described below under core/simulation. The approximated Sor depends on the validity of several idealized assumptions, which are rarely satisfied in practice:

  • That no B is present in the injected A, and that most of the hydrolysis reaction occurs during shut-in (no flow), so that B and unreacted A are exactly together before backflow begins. In reality, some reaction takes place during injection and production, and there always is some B present in the A as purchased. These two sources explain the high ethyl alcohol "tail" observed in Fig. 2.
  • That Sor is uniform throughout the formation tested. In practice, however, there often is evidence of several layers with different saturations in a given completion.
  • That the injected tracer-carrying fluids are stationary in the reservoir throughout the shut-in period. Actually, fluids sometimes relocate during the shut-in period, because of pressure gradients across the field or pressure differences within subzones of the test completion.
  • That the fluids inject uniformly into subzones and subsequently produce back to the test well reversibly. Total fluid flow reversibility is not observed in many tests.

Obtaining a more reliable answer for Sor requires a detailed simulation of the actual test procedure for a given SWCT test. Simulators are available to account for all the nonideal situations listed above. Simulation is time-consuming and is an added expense, but in our experience, it always is justifiable and its expense is small compared to that of field data acquisition.


KA = equilibrium partition coefficient for tracer A
Ke = oil/water partition coefficient for ester
QpA = volume required to produce tracer A, bbl
QpB = volume required to produce tracer B, bbl
Sor = residual oil saturation, fraction of PV
ve = time-weighted velocity of ester
vw = time-weighted velocity of water
βA = retardation factor for tracer A
βe = retardation factor for ester


  1. 1.0 1.1 Tomich, J.F., Dalton, R.L.J., Deans, H.A. et al. 1973. Single-Well Tracer Method to Measure Residual Oil Saturation. J Pet Technol 25 (2): 211–218. SPE-3792-PA.

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See also

Single well chemical tracer test

Well to well tracer tests