Basic Surveillance

1. Basic Surveillance Using Pressure-Transient Data to Monitor Well & Reservoir Performance

2. Basic Surveillance • An oil or gas field requires surveillance of individual well behaviour to identify potential problems and opportunities to improve performance. • The objective of “Basic Surveillance” is to answer the following two questions: • has the well-performance changed? • has the reservoir pressure deviated from the expected trend?

3. Basic Surveillance & Well-Test Analysis • Over the life of a well, there will be opportunities (planned or otherwise) to carry out a shut-in and measure a pressure-transient response. • Analysis of each set of pressure-transient data can be used to help answer the two “Basic Surveillance” questions: • compare “Derivative plots” to identify changes in well performance • compare “Superposition Plots” to track changes in the reservoir pressure.

4. Basic Surveillance Spreadsheet • The “Basic Surveillance” spreadsheet is intended to replace specialised well-test software when carrying out Derivative and Superposition plot calculations and comparisons. • All formulas and source-code are “open” to allow users to see how these calculations are done. • The spreadsheet can be modified to include customised calculations and summary sheets • Download from www.welltestsolutions.com

5. Demo - Spreadsheet Layout PVT & Units: define the test-type and the units for the comparison plots. Also sets the PVT data for gas-wells. Note the units table has a row to set custom units. PBU: each shut-in uses one of these sheets which previews each plot, and sets a line to estimate parameters. The input units and test-type for each shut-in can be set independent of the comparison plots setting.

6. New “PBU” Sheet in Workbook New “PBU” Sheet New “PBU” Sheet Surveillance over the Well History

7. Demo - Enter Data for a PBU • duplicate the blank “PBU” sheet and re-name • This name is used for the comparison plot legend • Select the test-type/units and fill in the static-data • click on the “Edit Test Data” button • This turns off the calculations to allow EXCEL to work faster and avoid unnecessary sheet updates. • copy & paste the rate data • copy & paste the pressure data • Note: rate and pressure data must use the same time format (e.g. date) and time basis.

8. Note: rate “qi” starts at time “ti” P* m =162.6 Bµ/kh Pressure during SI 0. 100. 200. 300. Superposition(q(t),Δt) Superposition Plot Assuming radial-flow and given an arbitrary rate-history with “n” rate-changes prior to a shut-in, the “Superposition Plot” can be represented by the following equation: Pressure data that reflects radial-flow in the reservoir will show a straight-line on the Superposition Plot with slope “m” and intercept “P*” Note that “P*” is a fictitious value with no physical meaning! This pressure does not exist anywhere in the reservoir!

9. 0 10 -1 10 -2 10 -2 -1 0 1 2 10 10 10 10 10 The Derivative Plot Two special transforms of the data are plotted together on log-log scales: “Delta-p” curve “Derivative” curve

10. 0 10 Pressure during SI -1 10 0. 100. 200. 300. Superposition(q(t),Δt) -2 10 -2 -1 0 1 2 10 10 10 10 10 Derivative-Plot “Derivative” Curve Superposition Plot Derivative Plot

11. p(Δt) p(Δt=0) “delta-p” = (p(Δt)-p(Δt=0))/q Δt Derivative-Plot “Delta-p” Curve Note the rate normalisation... shut-in

12. 0 10 proportional to a “skin” -1 10 derivative “stabilisation”= straight-line on superposition plot and yields a permeability-thickness characteristic shape -2 10 -2 -1 0 1 2 10 10 10 10 10 Derivative Plot Features The “derivative plot” reflects the completion and reservoir parameters that control well performance.

13. The “Half log-cycle” Rule “Ignore any feature in the derivative curve that spans less than half a log-cycle along the time axis.” • a stabilisation, linear trend, “hump”, or “dip” must span at least half a log-cycle before being considered significant. • any feature that fails this test is completely unrelated to the reservoir characteristics. • No further explanation is required.

14. Demo - Set-up Analysis Plots • Select “Begin Analysis” button • Select “SI Start” button and slide red marker to start of the shut-in. • Note zoom function and importance of finding exact start to get right derivative “delta-p” curve. • Select “SI End” button and slide green marker to the end of the shut-in. • Select “Set KH” button to display derivative plot. • Select “Set P*” button to display superposition plot. • NOTE: need both KH and P* set to calculate the skin. This is a limitation of the single “scroll-bar” interface.

15. Detect Changes in Well Performance • Given multiple sets of shut-in data, derivative plots can be directly compared to one another (plot overlay) • This comparison is valid at any reservoir pressure • If the shape of the derivative curve for each shut-in is the same, then there has been no change in reservoir properties • If the separation between a stabilisation and the “delta-p” curve is the same, then there has been no change in skin

16. Detect Changes in Reservoir Pressure • Given multiple sets shut-in data, Superposition Plots can be directly compared to one another for wells in a developed field (pss flow) • The sets of data should contain a sequence of parallel straight lines • i.e. a common reservoir permeability-thickness • The individual values of “P*” are meaningless because “P*” is a fictitious value. • The trend in the values of P* will run in parallel to the trend of the reservoir pressure.

17. Demo - Spot the Changes • un-hide the second shut-in in the example workbook. • define a stabilisation and P* using the KH from the first shut-in. • on the sheet for the first shut-in, select the “Update Comparison Plots” button. • on the sheet for the second shut-in, select the “Update Comparison Plots” button. • Look at the comparison derivative plot, what is the same and what has changed? • Look at the comparison superposition plot, has the reservoir pressure gone up or down?

18. The Rate Measurements • What rate values should be used for the analysis? • Single-phase flow: • use the measured rates for that phase • Multi-phase flow: • use the TOTAL sand-face rate, “qsf”, with B=1, µ=1: e.g. black oil: qsf = qo*Bo + [qg-qo(Rs-Rsi)]Bg + qw*Bw • if the well originally had single-phase flow: • compute an “equivalent phase-rate” by dividing qsf by that phase’s volume factor, and... • use that phase volume-factor and viscosity in the analysis. • this is a handy way to track reservoir mobility changes with respect to the initial behaviour of the well.

19. The Rate-History • How much rate data should be used to define the rate-history for the analysis? • For a new well: • use all the available rate data or... • experiment to find the amount of data needed to obtain a consistent derivative plot. • For a well in a developed field (pss flow): • this choice is more complicated...

20. Time-to-Pseudo-Steady-State (Tpss) • A pressure transient "disappears" once it reaches the boundary. • Therefore, the well "forgets" a transient after an amount of time greater than Tpss Time to Pseudo-Steady-State

21. Tpss contributes to Transient Response Prior History contributes to Material-Balance Contributions to a Shut-in

22. Rate-History for a Developed Field • Including rates prior to the “Tpss” period implies that well-test analysis can account for the material-balance of the system. • This is correct ONLY for simple volumetric material-balance with a constant compressibility. This is obviously not correct for real reservoirs with a complex production process. • In general, the rate-history should be limited to “Tpss” • The resulting “P*” values will reflect the current state of the drainage-area (but are still fictitious values not to be taken literally) • Across multiple shut-ins, the trend of “P*” using a “Tpss” rate-history will parallel the trend in average pressure. • The material-balance contribution is left out of the “P*” values, so whatever process is controlling material-balance can be reflected in changes of “P*” from one shut-in to the next.

23. d2 Rinv(Tpss) d1 d3 d4 How to Estimate Tpss 1) Identify the features that define the drainage-area for the well. 2) Identify the LARGEST distance “d” between the well and one of those features. 3) Compute the time, Tpss, such that the radius-of-investigation equals the distance “d” A well This procedure yields a conservative over-estimate of Tpss. This is preferable to an under-estimate which could result in a rate-history that distorts the analysis plots.

24. Demo - Using Tpss • Enter a value of 5000 feet for the “largest distance” in the static-data • note Tpss is calculated in results • Enter a small value for the “estimated Tpss” in the static-data. • note that the analysis plots change shape because the rate-history is truncated to the “estimated Tpss” duration.

25. Well-Test Analysis Steps • A complete analysis will progress through four steps: • Basic Surveillance to find valid sets of data that yield consistent information about basic KH, skin, and P* behaviour. • Interpretation of the derivative plot to understand the shape of the response, and to explain changes in behaviour. • Type-curve Analysis to quantify the observed response in terms of a relevant well and reservoir model. • Integrated Analysis that incorporates other information about the well and reservoir to obtain a useful set of results. • Embark on Interpretation, Type-curve analysis, and Integrated analysis after getting advice on: • Data quality: is it worth pursuing a detailed analysis? • Analysis objectives: is it feasible to derive the analysis results that will provide useful information?