Testing system combines advantages of wire line and drill stem testers

Neal G. Skinner, Paul D. Ringgenberg
Halliburton Energy Services
Dallas

Mark A. Proett, Aadireddy Reddy, Wilson C. Chin
Halliburton Energy Services
Houston

• Equation Box [Adobe PDF Format][54,102 bytes]

A new early formation pressure system (EFPS) combines the advantages of a drill stem test (DST) and a wire line formation tester (WFT) and provides a new method for performing formation pressure tests.

The EFPS has been successfully field tested and may be used instead of, or in conjunction with, a DST or WFT to determine formation pressures and permeabilities.

One advantage the EFPS has over the DST and WFT is that only a minimum of equipment and personnel is required to perform an EFPS test. This makes the technique attractive in remote locations or locations where deck space is limited.

The EFPS can be used during a wiper trip to perform a series of quick formation pressure tests similar to those run with a wire line formation tester. The EFPS consists of two inflatable packers, a pump, and high precision quartz gauges that are conveyed by drill pipe (Fig. 1 [78,849 bytes]).

Drill pipe pressure inflates the packers, and pipe reciprocation initiates drawdowns. Typically, the tool is deployed during wiper trips, and the bottom hole assembly (BHA) can include any type of logging while drilling (LWD) tools.

EFPS field test results are analyzed with a new exact solution of the spherical-flow well-test equation that is valid for all time. The solution is used to predict formation pressure and permeability from early to intermediate-time pressure transients.

This scope is not possible with conventional drill stem test (DST) analytical models because they do not model the entire time behavior of the pressure response.

The new exact-spherical flow model, derived from first principles, includes general well bore storage effects. The model is solved in closed, analytical form, thus permitting convenient pressure response to theory matching using the complete time regime, including early, transitional, and late-time data.

Well test examples demonstrate accurate pore pressure and permeability predictions from the EFPS. Detailed numerical simulations over a wide range of conditions illustrate the utility and power of the new technique.

Conventional testing methods

Historically, two methods have been used to evaluate downhole formation pressures after drilling a well. The oldest method, the DST, dates back to the 1930s. A DST is a temporary completion of an open-hole or cased-hole well and is used to gather reservoir data.

DSTs can have a tremendous range of complexity. For instance, a 2,000-ft land test is much simpler to plan and execute than a high-pressure, high-temperature DST from an offshore floater; however, there are many similarities.

In each case, a set of DST tools is run into the well on drill pipe or tubing. A packer isolates the zone of interest from the hydrostatic head of the drilling or completion fluid above the formation. A tester valve is then opened to flow the well and later closed in order to shut-in the well.

Pressure gauges record the pressure history during the drawdowns that occur during well flows and buildups, while the well is shut-in. At the conclusion of the DST, a circulating valve opens, the well is circulated, and the DST tools and the pipe are withdrawn from the hole.

The WFT was introduced in the mid-1950s as a sampling tool and has grown in acceptance as an openhole service for pressure testing and sampling over the past 20 years. The WFT is run in the hole on electric wire line.

Instead of sealing a section of formation with a packer, a donut-shaped rubber pad is pressed against the side of the well bore to isolate a small zone of interest from mud hydrostatic. Formation fluid is drawn through the pad into the WFT, usually performed by moving an adjustable piston inside the tool.

As the fluid is drawn into the tool, the formation pressure drops. After the fluid has been drawn from the formation, the formation pressure increases. During the test, real-time formation pressure measurements are transmitted to the surface through the electric wire line. At the conclusion of the test, the pad is released from the well bore and the WFT is repositioned for another test.

Recently, a new generation of WFTs was introduced. In this class of WFTs, an electric pump moves fluid from the formation during the test. These tools utilize increased WFT flow rates and volumes and are more versatile than the earlier WFT tools.

Conventional tool disadvantages

DSTs and WFTs perform tests after drilling, and in most cases, more than a day after drilling the zones of interest. During this time, a substantial volume of mud filtrate can invade the formation, causing over pressuring and formation damage near the well bore.

This can severely distort the pressure and permeability measurements made by the WFT. A DST attempts to compensate for this by extending the test time; thereby flushing out the invaded zone. Frequently, when a well is completed, invasion effects can last more than a week.

In some parts of the world, WFTs tend to stick in the hole. Because these tools are normally run on electric line, the available force needed to pull the tool free is limited. The EFPS tool is run on drill pipe; therefore, more force may be applied to pull or rotate the tool free.

In a typical DST, only one interval is tested, while a WFT can make hundreds of test points. This provides reservoir delineation with pressure gradient plots that identify oil, water, and gas contacts, and permeability plots.

EFPS advantages

To provide more accurate pressure and permeability measurements, the EFPS was designed to run immediately after a zone of interest is penetrated. The EFPS can be run in a wiper trip during the drilling program with as many as 20 pressure tests performed for each trip.

A short, 32-in. interval is tested between dual-inflatable packers, making the measurement much like the WFT but with reduced invasion distortion. A 1,000 cu cm test chamber can be used for creating a drawdown, making the depth of investigation substantially greater than a WFT.

Because the EFPS is designed to circulate mud through the drill pipe while tripping, differential sticking is minimized. Also, because it is a drill pipe-deployed tool, it can be rotated and pulled with substantially more force than a WFT.

This reduces the risk of sticking and makes testing in horizontal and extended reach wells less expensive and safer than testing with a drill pipe-deployed WFT.

EFPS tool system

Fig. 1 is a schematic of a tool system used to perform an early evaluation test. An upper tool contains two opposing, spring-biased operating pistons, a ball valve used to isolate the inside diameter of the tool, an inflation valve, a bypass valve, and a pair of ratchets used to sequence the operation of the tool.

A lower tool contains a pair of inflatable packers, electronic memory recorders, and a pump. The volume of one stroke of the pump can be adjusted at the surface before running the system. A drill bit is positioned at the bottom of the tool system.

Both tools are similar in construction to those normally used in DSTs, and therefore do not have the capability to withstand the rigors of drilling. The drill bit is included to provide a restricted flow path resulting in a differential pressure between the OD and ID of the tool system during circulation.

The tool is run in with the ball valve open (Fig. 1) and the bypass and inflation valves closed. In this configuration, the tool is passive. High-rate circulation can be repeatedly established through the tool.

When the circulation rate is modulated in a particular, predetermined manner, the tool shifts position, the ball valve closes, and the inflation and bypass valves open (Fig. 2 [83,399 bytes]). The ball valve isolates the ID of the drill pipe and allows pressurization of the pipe without flow.

The inflation valve opens to allow pipe pressure in the tool ID above the ball to inflate the packers and seal off the zone of interest between the packers. The bypass opens to equalize hydrostatic pressure above the top packer with pressure below the bottom packer. This equalization prevents hydraulic forces from trying to move the system up or down the hole during testing.

In Fig. 3 [73,417 bytes], pressure is applied to the ID of the drill pipe at the surface. The packers inflate and seal off the zone of interest. Weight is applied to the pipe string to verify that the packers are set. This action also resets the pump to its bottom position.

As shown in Fig. 4 [80,827 bytes], while pipe pressure is maintained, tension is applied to the pipe at the surface. Pipe tension strokes the pump and causes a withdrawal of fluids trapped between the packers, resulting in a formation drawdown.

Pipe tension is maintained for several minutes, and a buildup results from the formation's attempt to replace the withdrawn fluid. If additional drawdown/buildup cycles are required, weight is set down on the pipe at the surface.

This resets the pump and another pump stroke can be taken. High-accuracy, high-resolution electronic memory gauges record tool OD pressure between the packers in nonvolatile memory while the system is in the hole.

At the conclusion of the test, the pressure in the pipe is released. The packers deflate, the ball valve reopens, the bypass and inflation valves close, and the tool returns to the state shown in Fig. 1. High rate circulation can then resume.

The system can be repositioned in the well for another test or retrieved to the surface. The tool system can perform as many tests as desired in a single trip. The number of tests that can be performed during one run, however, may be limited by the number of times the inflatable packers will successfully set.

Early time, pressure-transient analysis

The EFPS system has a relatively small area exposed to the well bore compared to traditional DST tools. Thus, it is more closely related to a wire line formation tester from an analysis standpoint.

If the horizontal spacing of the packers is small with respect to the bed boundaries, then for early time analysis, spherical flow can be assumed. This is through detailed simulations.

The equivalent source radius of the EFPS system can be estimated by equating the area of a spherical source, Asi, to that cylindrical area exposed between the packers (See Equation box, Equations 1 and 2).

The geometric shape factor l is introduced to make corrections to the source radius, rs, based on the numerical simulations. Using rs, the exact, closed-form solution for spherical flow with well bore storage is rigorously developed from first principles presented in the following equations and is expressed in terms of complex complementary error functions in Equations 19-21.

Previously published solutions have been expressed in the Laplace domain and require numerical solution.² Having the complete closed-form solution in the time domain enables faster and more-accurate history matching of the pressure-transient data.

Traditional pressure testing analytical techniques for WFTs and DST use late-time data to estimate permeability and shutin pressure.^{3 4}

The EFPS system and WFTs have relatively small test volumes when compared to the fluid in the well bore and flow lines of the tool. This causes the early time, pressure-transient data to be storage dominated.

The expansion of the fluid in the well bore and flow lines of the test tool distort the early time data and make it unusable by traditional late-time data techniques. This distortion is most evident in tight zones.⁵

Recent papers have introduced a new tight-zone analytical technique.^{5 6} This technique is especially suited to low permeability zones (0.001-1.0 md) where traditional radial (Horner) and spherical models fail.

This method can determine permeability and initial sand-face pressure using early time, pressure-buildup data that drastically shortens testing times. Flow line storage distorts all but the very late-time data in tight-zone testing, but the tight-zone model accurately predicts this distortion in wire line testers.

The tight-zone model is an approximate solution, and while it can be applied to wire line testers with a small probe, the EFPS system with its larger packer area requires the new exact solution.

The tight-zone model, derived earlier using simplifying assumptions, has been rigorously proven to be a subset of the new exact solution. This new exact solution reduces to the exponential approximation, resulting from the earlier tight-zone analysis.

This more complete solution applies to early, intermediate, and late times, and can be used for extended time matching for high or low permeability zones.¹

In situ compressibility, permeability

By knowing the volume of fluid in communication with the test piston and the rate of change in pressure during the drawdown, the well bore in situ compressibility can be estimated (Equation box, Very short-time solution).

Alternately, multiple regression can be used to determine fluid compressibility, permeability, and formation pressure when porosity and viscosity are estimated (Equations 9 and 19). Fluid compressibility is determined by this method by assuming the well bore fluid compressibility is equal to the formation compressibility, cs = cf, in the dimensionless variables (Equations 7-9).

This in situ compressibility is used because it is more accurate than a best-guess estimate that could lead to an incorrect and unsatisfactory calculation of permeability and formation pressure.

This well bore storage compressibility (cs) is unlikely to be the compressibility of the fluid in the formation (cf) except in certain situations, such as in:

• A large volume drawdown
• Multiple drawdown tests in which fluid between the packers and test chamber has been replaced by formation fluid.

However, the formation fluids in the vicinity of the well bore are usually mixed with mud filtrate as a result of the invasion process. Therefore, the well bore fluid compressibility can be assumed to nearly equal the compressibility of the mud filtrate present in the formation pore space affected by a short pressure test. This is particularly true for small-volume drawdowns.

Even with substantial differences between formation fluid compressibility (cf) and flow line (cfl) compressibility, the exact-zone model still yields accurate estimates of Pf and Kf.

This is shown by Fig. 5 [59,916 bytes] where the exact solution is used to determine the drawdown pressure differences with the formation compressibility assumed to be ten times greater than that of the well bore fluid (cf = 10 cs).

Fig. 5 is a surface plot with the vertical axis being the ratio of the pressure determined by the exact solution (Equation 19). The formation compressibility is assumed to be 10 times greater than that of the well bore fluid (cf = 10 cs), divided by the determined pressure, assuming the compressibilities are equal (cf = cs).

Differences between formation and well bore compressibility have less than a 5% variation over a wide range of test conditions. There is a maximum variation of 33% at permeabilities of less than 1 md with short drawdowns of less than 1 sec.

Because the EFPS system drawdown rate can be regulated from the surface-low permeability zones, drawdown time can be extended over to several seconds, reducing this potential error. When the difference between compressibilities is reduced, the maximum error is reduced substantially, generally to less than 5%.

References

1. Proett, M.A., and Chin, W C., "Supercharge Pressure Compensation Using a New Wire line Testing Method and Newly Developed Early Time Spherical Flow Model," SPE paper 36524, presented at the 71st SPE Annual Technical Conference and Exhibition, Denver, Oct. 6-7, 1996.
2. Joseph, J.A., and Koederitz, L.F., "Unsteady-State Spherical Flow With Storage and Skin," SPE Engineers Journal, December 1985.
3. Stewart, G., and Wittman, M., "Interpretation of the Pressure Response of the Repeat Formation Tester," SPE paper 8362, presented at the 54th Annual Technical Conference and Exhibition of the SPE, Las Vegas, 1979.
4. Raghavan, R., Well Test Analysis, PTR Prentice Hall, Englewood Cliff, N.J., pp. 69-70, 1993.
5. Proett, M.A., Waid, M.C., Heinze, J., and Franki, M.W., "Low Permeability Interpretation Using a New Wire line Formation Tester 'Tight Zone' Pressure Transient Analysis," paper SPWLA-94-III, presented at the 35th Annual Symposium, Tulsa, June 1994.
6. Proett, M.A., Waid, M.C., and Kessler, C., "Real Time Pressure Transient Analysis Methods Applied to Wire line Formation Test Data," SPE paper 28449, presented at the 69th Annual Technical Conference, New Orleans, Sept. 25-28, 1994.
7. Waid, M.C., Proett, M.A., Vasquez, R., Chen, C.C., and Ford, W.T., "Interpretation of Wire line Formation Tester Pressure Response, Mud Supercharging and Mud Invasion Effects," paper SPWLA-92-HH paper, presented at the 33rd Annual Symposium, Oklahoma City, June 1992.
8. Chin, W.C., Formation Invasion, With Applications To Measurement While Drilling, Time Lapse Analysis And Formation Damage, Gulf Publishing Co., Houston, pp. 93-98, 1995.
9. Churchill, R.V., Complex Variables and Applications, McGraw-Hill Book Co., New York, Second Edition, pp. 265-266, 1960.

The Authors