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Single well chemical tracer test

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The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile.

Primary use

The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets. Secondarily, it is used to measure Swc accurately for better evaluation of original oil in place (OOIP). Fractional flow measurement provides realistic input for simulator models used to calculate expected waterflood performance.

History

The first SWCT test for residual oil saturation (Sor) was run in the East Texas Field in 1968.[1] Patent rights were issued in 1971.[2] Since then, numerous oil companies have used the SWCT method.[3][4][5][6][7] More than 400 SWCT tests have been carried out, mainly to measure Sor after waterflooding.

The SWCT method has gained considerable recognition over the past few years because of increasing interest in the quantitative measurement of Sor. Some experts[8][9] consider the SWCT test to be the method of choice because of its demonstrated accuracy and reasonable cost.

Measuring residual oil saturation

Accurate Sor measurement is important because of a combination of basic problems in oil recovery. The industry still produces less than half the oil in the reservoirs discovered, and nearly all that oil is produced using traditional primary and secondary recovery methods.[10] Furthermore, as the cost of finding new reserves continues to increase, especially in the US, the oil remaining in old fields becomes a significant economic target for infill drilling and IOR projects.

In every target field, the quantity and location of the remaining oil must be determined. Fig. 1a illustrates the principle of material balance, as applied to an oil reservoir. The entire area of the graph represents the reservoir pore volume (Vp), which is known with varying degrees of uncertainty. The produced oil, corrected back to reservoir conditions, is the middle area; its accuracy, however, depends on how thoroughly production records have been kept.

The uppermost area is the connate water, which is known only as well as available methods and coverage of measurements allow. The lowermost area, the remaining oil, can be expressed as an average saturation of oil  , if we accept the total pore volume Vp, produced oil, and Swc values as being accurate.

If a given field has been waterflooded, the fraction of the OOIP displaced by the water is a critical parameter. Testing for Sor in watered-out wells in the field can determine the maximum waterflood displacement efficiency. A significant difference between the material-balance So and the measured Sor would indicate the presence of bypassed oil. This would signify that parts of the reservoir had not been contacted by injected water, or had not received sufficient water throughput to reach Sor. This concept is shown in Fig. 1b.

A reliable in-situ measurement of Sor simultaneously defines the target for enhanced oil recovery (EOR) and allows estimation of the potential bypassed (mobile) oil in the field. This moveable oil is the target for infill drilling and/or flood sweep efficiency improvements.

Because Sor varies greatly with formation type, oil/water properties, and other variables that are not completely understood (e.g., wettability changes caused by water flood practices), Sor measurements range from < 10% to > 45%. There is no reliable way to predict Sor with acceptable accuracy for most reservoirs. Furthermore, measuring residual oil is not easy. Laboratory corefloods performed at other than native state wettability are unreliable.[11]

Well logs can give vertical profiles of Sor under optimal conditions, but their results are not absolute. Logs of all types require calibration by an independent method, which gives either a quantitative So at some point or an average So over some layer. Pressure cores or sponge cores can provide this calibration, but require a new well and are subject to saturation disturbances caused by mud filtrate invasion.

An advantage of the SWCT method is that it pushes tracers beyond damaged regions near the wellbore and into layers that are known to be at residual oil conditions. The tracers go where water is contacting the residual oil, as shown in Fig. 1b.

In an SWCT test, the formation volume sampled is large enough to be representative. A typical test quickly investigates hundreds of barrels of pore space in an existing watered-out well. The tracer-bearing fluids are produced back into the well without disturbing the formation, allowing further testing.

Measuring connate water saturation

Connate water saturation is more variable (and less predictable) than Sor, with Swc measurements ranging from > 50% in certain rock types to < 5% in unusual reservoir situations. Large variations within the producing intervals of major reservoirs are well documented.[9]

As Figs. 1a and 1b show, estimates of recoverable oil depend fundamentally on knowing Swc. Oil-based coring can provide reliable results and is an effective choice if its expense can be justified at the time a well is drilled. Electric logs can give vertical profiles, but as with Sor, require calibration for quantitative Swc measurement.

Deans and Shallenberger[12] reported the first application of the SWCT method for measuring Swc. As in the case when measuring Sor, the reservoir volume sampled is large and the test is nondestructive, which is especially important for a producing oil well. The tracers used in measuring Swc are nonhazardous oxyhydrocarbons, so that no contaminated oil needs to be disposed of after the SWCT test. Most importantly, though, the test holds a high success rate—every known SWCT test for Swc has yielded quantitative results.

Nomenclature

  = average oil saturation in the reservoir, fraction of PV
Sor = residual oil saturation, fraction of PV
Swc = connate water saturation, fraction of PV
Vp = total pore volume, bbl

References

  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. http://dx.doi.org/10.2118/3792-PA
  2. Deans, H.A. 1971. Method of Determining Fluid Saturations in Reservoirs. US Patent No. 3,623,842.
  3. Deans, H.A. and Majoros, S. 1980. The Single-Well Chemical Tracer Method for Measuring Residual Oil Saturation, Final report, Contract No. DOE/BC20006-18. Washington, DC: US DOE.
  4. O'Brien, L.J., Cooke, R.S., and Willis, H.R. 1978. Oil Saturation Measurements at Brown and East Voss Tannehill Fields. J Pet Technol 30 (1): 17-25. SPE-6370-PA. http://dx.doi.org/10.2118/6370-PA
  5. Sheely, C.Q. 1978. Description of Field Tests To Determine Residual Oil Saturation by Single-Well Tracer Method. J Pet Technol 30 (2): 194-202. SPE-5840-PA. http://dx.doi.org/10.2118/5840-PA
  6. Thomas, E.C. and Ausburn, B.E. 1979. Determining Swept-Zone Residual Oil Saturation in a Slightly Consolidated Gulf Coast Sandstone Reservoir. J Pet Technol 31 (4): 513-524. SPE-5803-PA. http://dx.doi.org/10.2118/5803-PA
  7. Nute, A.J. 1983. Design and Evaluation of a Gravity-Stable, Miscible CO2-Solvent Flood, Bay St. Elaine Field. Presented at the Middle East Oil Technical Conference and Exhibition, Bahrain, 14-17 March 1983. SPE-11506-MS. http://dx.doi.org/10.2118/11506-MS
  8. Chang, M.M., Maerefat, N.L., Tomutsa, L. et al. 1988. Evaluation and Comparison of Residual Oil Saturation Determination Techniques. SPE Form Eval 3 (1): 251-262. SPE-14887-PA. http://dx.doi.org/10.2118/14887-PA
  9. 9.0 9.1 Donaldson, E.C. and Staub, H.L. 1981. Comparison of Methods for Measurement of Oil Saturation. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4-7 October 1981. SPE-10298-MS. http://dx.doi.org/10.2118/10298-MS
  10. Energy Information Administration (EIA). 1980. Annual Report to Congress, Volume 3, DOE/EIA-0173(79)/3, Washington, DC (July 1979).
  11. Salathiel, R.A. 1973. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks. J Pet Technol 25 (10): 1216–1224. SPE-4104-PA. http://dx.doi.org/10.2118/4104-PA
  12. Deans, H.A. and Shallenberger, L.K. 1974. Single-Well Chemical Tracer Method to Measure Connate Water Saturation. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 22-24 April 1974. SPE-4755-MS. http://dx.doi.org/10.2118/4755-MS

Noteworthy papers in OnePetro

Cockin, A.P., Malcolm, L.T., McGuire, P.L. et al. 2000. Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas Flood at Prudhoe Bay. SPE Res Eval & Eng 3 (6): 544-551. SPE-68051-PA. http://dx.doi.org/10.2118/68051-PA

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