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Wireline Formation Testers

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Wireline Formation Testers

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  1. Wireline Formation Testers • Wireline formation testers are used to obtain • Pressure profiles • Formation fluid samples • Permeability indicators • This information is crucial during exploration and development of oil and gas fields

  2. Wireline Formation TestersDifferent types

  3. Proper reservoir management requires formation pressure measurements in a wide range of conditions. Collecting representative formation fluid samples and determining premeability anisotropy are equally important. Formation pressure measurements taken within a well can be plotted versus true vertical depth to produce a pressure profile. The resulting pressure profile is extremely valuable in analyzing virgin and developed reservoirs. In developed reservoirs, wireline testers are used to Characterize vertical and horizontal barriers Assess vertical permeability Determine hydraulic communication between wells Detect fluid contact movement In virgin reservoirs, vertical pressure profiles are obtained to Determine fluid contact level Determine formation fluid density in situ Characterize reservoir heterogeneities Why Wireline Testing?

  4. Wireline formation testers are also used to collect formation fluid samples, the MDT tool attempts to improve the quality of samples by using techniques for downhole fluid analysis Tests from wireline testers provide mobility profiles that help to pinpoint zones of better productivity. The recorded transient pressure response at each station can be analyzed to estimate permeability In homogeneous formations, the multiprobe tester scan estimate horizontal and vertical mobilities In laminated formations, this tool enables the study of potential permeability barriers and their effect on vertical fluid movement Wireline formation testing data are essential for analyzing and improving reservoir performance and making reliable predictions, which are vital to optimizing reservoir development and management Why Wireline Testing?

  5. BASIC • Connected directly to the hydraulic power module, the single-probe module contains a probe assembly with packer and telescoping backup pistons, and connects the tool flowline to the reservoir. • Can be placed anywhere on the string, but it must be directly connected to the hydraulic power module • Extends against the borehole wall to provide a fluid path from the reservoir to the flowline. • The pretest is used to ensure a good hydraulic seal, obtain accurate formation pressure recordings and determine permeability • Max volume pretest chamber 20 cm3 • Service unit controls the sampling pressure, pretest flow rate and volume from the surface, allows selection of optimal values for the various formation characteristics that can occur during a pressure measurement sequence.

  6. Standard MDT tool • Designed to take several measurements and fluid samples during one trip in the well • The configuration, which extend the capabilities of existing single-probe testers, provides a basic tool to which additional modules – and therefore capabilities – can be added. • Advantages over existing tools include flowline temperature and flowline fluid resistivity determinations, collection of several fluid samples per trip, standard operations in a larger range of hole sizes, extended pressure accuracy and dynamic response, and surface controlled pretest rate, volume and sampling pressure. • Usually combined with a gamma ray device for depth control Schlumberger

  7. Extends against the borehole wall to provide a fluid path from the reservoir to the flowline. • The pretest is used to ensure a good hydraulic seal, obtain accurate formation pressure recordings and determine permeability • Max volume pretest chamber 20 cm3

  8. Pressure test sequence P High perm Low perm tight t

  9. Supercharging

  10. Supercharging • In low-permeability formations, wireline formation pressure measurements are sometimes hampered by the “supercharging” phenomenon. • Caused because the permeability of the mudcake is not exactly zero but has some small value. This permeability allows a finite continuous flow of filtrate across the mudcake. • In a low-permeability formation, the resistance to fluid flow because of the mudcake can be the same order of magnitude as the resistance of the formation to accepting fluid. • Thus, a standard wireline pressure measurement will not be sufficient to measure the pressure of the virgin formation, because a residual finite pressure difference remains between the formation at the mudcake interface and the virgin formation some distance away.

  11. Pressure profiles

  12. Pressure Profiles • In thick reservoirs with relatively high permeabilities, vertical pressure profiles are used to determine in-situ fluid densities and fluid contact level. • This type of pressure measurements requires gauge with high accuracy and resolution. Standard quartz gauges, although suitable for fluid gradient determination, require long stabilization times when subjected to sudden changes in temperature or pressure, a common occurrence during formation tests. • Strain gauges have a better dynamic response,but do not offer the accuracy or resolution needed for most fluid gradient determinations. • A new gauge was needed that could combine the accuracy and resolution of the quartz gauge with the dynamic response of the strain gauge. These requirements were met in the CQG (Crystal Quartz Gauge).

  13. Resistivity Wm SW Pressure bar 0 1 Oil/water contact Free water level Free water level (FWL) from pressure

  14. Resistivity measurements New features include a flowline resistivity sensor and temperature sensor and isolation valve. The resistivity measurement helps to discriminate filtrate from water-base mud and formation fluids. Also useful when taking formation water samples in wells drilled with oil-base mud.

  15. OFA module • The second requirement for the recovery of PVT-quality fluid samples is a detection system to indicate fluid type. The sensor in the probe module provides a resistivity measurement over a wide range. • Some conditions, in particular wells drilled with OBM, may require the OFA module. • This module, run immediately below the probe module, uses optical analysis techniques to identify the fluid in the flowline

  16. OFA module • OFA (Optical Fluid Analysis) is used for fluid analysis with two sensor systems: one for liquid detection and analysis and the other for gas detection. The flowline passes through two independent optical sensors. In one cell, absorption spectroscopy is used to detect and analyze liquid. In the other cell, a special type of optical reflection measurement detect gas. • This allows wellsite personnel to decide whether to divert the flow into a sample chamber, or increase the sampling pressure above bubblepoint. • It can also be used to verify that the formation contains only water or only gas and that a sample is not required. Thus, the sample chambers in the tool are kept available for desired fluids only. • Even when OBM is used it is possible to track the transition from borehole mud, to filtrate, to connate oil as long as the two oils differs in color.

  17. Sampling • Sample chambers available with 1, 2 ¾ and 6 gal. The software will handle up to 12 sample units, but length and weight limitations make only 5 or 6 units practical per trip. • Each chamber has an electromechanically actuated throttle (seal) valve, which is controlled from the surface and directs sampled fluid to the selected chamber in any order. The valve can operate in one of two modes. In seal mode, the valve can be either fully open or fully closed. In throttle mode, the valve operates as a variable orififce that automatically opens and closes to maintain the flowing pressure constant. The throttle valve is a dynamic valve, constantly adjusted to maintain a specified flowline sampling pressure within an error band. The engineer specifies the operating parameters of this valve. • In addition, the sample chamber has a drain valve for connecting the sample drainage equipment and a transport valve for sealing the sample in the module.

  18. Dual packer • Provides two inflatable packer elements to isolate a borehole interval for testing and/or sampling. The pumpout module uses borehole fluid to inflate the packer elements to about 1000 psi above hydrostatic pressure. Spacing between the packer elements varies with the borehole size, min. distance is about 3 feet (92 cm). The entire borehole wall is open to the formation, so the fluid area is several 1000 x larger than with conventional probes. • Can be used as an alternative to conventional probes.

  19. Extrapolating pressure gradients • In some reservoirs, the gas-water contact cannot be identified by the pressure profile of Well 1 or Well 2. Therefore, no estimate of reservoir volume can be made. • However, by extrapolating the water gradient of well 1 and the gas gradients of well 2, it is possible to determine the gas-water contacts and estimate reservoir volume. This extrapolation shows that pressure readings taken near the wellbore reflect pressures that exist deep within the formation.

  20. Well I Well II Depth GWC ? GWC Pressure Pressure gradients

  21. Barrier detection • Flow barriers have prevented formation fluids from reaching equilibrium over geologic time. Because the fluid has not reached equilibrium, a potential difference exists on opposite sides of the barrier. This pressure potential means that formation fluid would flow if the barrier were removed. Variation in potential can easily be seen when carefully analyzing gradients and provides a means of identifying flow barriers. • Gradients may not be continuous through what is thought to be a single reservoir. In these instances, two or more similar of identical gradients can be identified; however, they can have a potential difference because of an existing flow barrier. Vertical flow barriers can be identified by this potential.

  22. Barrier detection

  23. Exercise 1 In a gas reservoir, that consist of sand zones and shale zones, two vertical wells are drilled (I and II). Well II is situated 500 m east of well I. Well I was drilled through sand zones A and B, Well II was drilled through 3 sand zones K, L and M. The thickness of these sand zones is between 20 m to 30 m with zones of shale in between. In each of these sand zones, to pressure tests were taken (MDT). The chart below shows the pressure in the different zones: Plot the pressure points on a depth vs. pressure plot and make a drawing of the geological structure and fluid system based on these pressure data

  24. Well I Well II A K Gas Gas 2637 GWC B Water Gas L M Gas ANSWER A K B L M

  25. Exercise 2 • MDT pressure measurements can be used to estimate barrier/communication between sandzones. In Figure 1 and Figure 2, the answer is given with folds and faults between two wells. The points were the pressure are measured are indicted on the figures (o). GWC is also known. • Draw on the pressure plot to the left how you expect the pressure points are situated in relation to each other, for the given geologic structure with gas-zones and water-zones. GWC and barriers are given on the drawing. Draw also the gradients (gas and water)

  26. Well 1 Well 2 Pressureplot Depth (meter) Gas GWC Water Gas GWC Water Pressure (bar) Draw the Draw the pressure points and Figure 1 Figure 1

  27. Well 1 Well 2 Gas GWC Water Gas GWC Water ANSWER Depth (meter) Pressureplot Pressure (bar)

  28. Well 1 Well 2 Barrier Gas Gas GWC GWC GWC Water Water Water Water Water Depth (meter) Pressureplot Pressure (bar) Figure 2 communication

  29. Well 1 Well 2 Barrier Gas Gas GWC GWC GWC Water Water Water Water Water ANSWER Depth (meter) Pressureplot Pressure (bar) communication

  30. Exercise 3 • MDT pressure measurements are used for barrier studies. Figure 3 shows a gas field with 8 wells. Figure 4 shows the pressure values for each of these wells from one sandzone A. Sandzone A has low permeability and for 3 of the wells the sand is almost tight. • Which 3 wells show almost tight sand (supercharge)? Based on the pressure plot, draw lines for tight faults/barriers between some of the wells on figure 3. Estimate the GWC for each segment.

  31. Well 6 Well 3 Well 4 Well 8 Well 1 Well 7 Well 2 Well 5 Figure 3

  32. Figure 4

  33. ANSWER

  34. Well 6 Well 3 GWC=4000 m Well 4 Well 8 Well 1 Well 7 Well 2 Well 5 ANSWER

  35. Karl Audun Lehne • Education: • University of Oslo & University of London • Experience: • UiS, Statoil, Total, IRIS, Statens Kartverk About the Author • Address: • UiS • E-mail:Karl.A.Lehne@uis.no • Phone: 91154518