Cement pulsation improves gas well cementing – Statistical Data Included

Ken Newman

Ongoing research successfully shows that application of the cement pulsation technique to the casing annulus delays cement gelation and maintains hydrostatic pressure. Maintenance of pressure should eliminate formation fluid influx during the cement transition period

A 1995 study by Westport Technology revealed that 15% of primary cement jobs fail, and that these cementing problems cost oil and gas-producing companies about $470 million annually. Approximately one-third of these problems are attributable to gas migration or formation water flow during placement and transition of the cement to set. In the 1990s, John Haberman of Texaco E&P proposed applying pressure pulses to the casing annulus above the cement to delay the onset of cement gelation and maintain the hydrostatic pressure. If the hydrostatic pressure is maintained, formation fluid influx during the cement transition period should be eliminated.

This article summarizes results from an ongoing research project funded by GTI, managed by CTES, L.C., and participated in by LSU to determine if cement pulsation (CP) does, indeed, reduce gas migration problems. The results discussed in this article show that the applied pressure pulses do maintain hydrostatic pressure while the cement is setting.


As soon as possible after the plug is bumped, the annular BOP is closed around the casing to seal the annulus. Then, a CP unit begins applying pressure pulses of about 100 psi, Fig. 1.

An air compressor continuously pressurizes an air tank. To pressurize the annulus, the control system opens a valve between the air tank and a water tank. The air pressure forces the water into the casing annulus and pressurizes it. To release pressure, the control system closes the pressurization valve and opens an exhaust valve. As pressure is released, water returns from the casing annulus to the water tank. Once pressure is fully released, water is added to the water tank if needed, to keep it full.

The pulses are quite slow, with built-in delays. Pressure is applied, followed by a delay of 10 to 25 sec. After the pressure is exhausted, there is another delay of 10 to 25 sec. Thus, a single pulse cycle lasts from 30 sec. to 1 mm. The volume of water displaced to the well for each pulse is determined by measuring the water level in the tank. This water volume is the “compressible volume” of the casing annulus. As the cement sets, the compressible volume of the casing annulus should decrease.


The purpose of the CP process is to keep the cement in motion, delaying the onset of gelation, and preventing a significant decrease in hydrostatic pressure in the cement. If hydrostatic pressure is maintained, fluid influx from the formation during the critical time between placement and setting of cement (sometimes called the transition period) should be reduced or eliminated.

As the pressure pulses travel down the casing annulus, one would expect the magnitude of the pulse to decrease due to pressure attenuation. Some of the objectives of this project are to determine how much the pressure attenuates, how much pressure reaches the bottom of the casing, and if the hydrostatic pressure is maintained.


Tests were performed on two very similar wells (Wells A and B) about 8,600 ft deep, with 5 1/2-in. casing inside a 7 7/8-in. hole. The lower 1,700 ft of each casing string were cemented. Instrumentation for both wells was accomplished by attaching three pressure and temperature gauges to the outside of the casing string. A 3/4-in. OD, “disposable” pressure/temperature gauge developed by CTES for this testing is shown in Fig. 2. In Fig. 3, the three wire-line cables from the three gauges can be seen being clamped to the casing, at a casing collar. As the casing and cables were run in the hole, clamps were attached to every third joint to support the cables.

One gauge was placed near the bottom of the cement column, one gauge in the middle and one gauge at the top. In Well A, the top gauge was just above the top of cement, in the drilling fluid. In Well B, the top gauge was just below the top of cement.

In both tests, the clamps used to attach the pressure and temperature gauges to the casing caused errors in the pressure calibration. The pressure data were adjusted for this calibration error, based upon the known hydrostatic pressure of the drilling fluid column at various depths.


The results from Wells A and B were similar. For brevity, only the results from B are shown in this article. Figs. 4 through 6 summarize the results from Well B. The following paragraphs are comments about the test results.

Initially, pulses were begun with 10-sec. delays after pressure was applied, and after exhausting the pressure, with 107-psi pulses introduced at the surface, Fig. 4. Four times during the process, the pulsing system was paused for 2 to 3 min. Each time the pulses were paused, there was a significant decrease in downhole pressure. It is believed that this pressure decrease was due to gel strength development in the cement. Within two to three pulses after pulsing was resumed, hydrostatic pressure was recovered.

After the first pause, pressure delays were changed to 20 sec. This delay allowed the CP system to supply more pressure, so that the pressure pulse amplitude at the surface became 114 psi.

The compressible volume is shown in the middle plot of Fig. 4. It decreased significantly during the first 30 min. of pulsation and then declined only slightly for the rest of the period. It is believed that the first decrease is due to gas working out of the system (which may also explain the variation in downhole pulse amplitude), and that the gradual decrease is due to the reduced compressibility of the cement as it sets.

Five minutes of pulsing, including the first pause, are displayed in Fig. 5. The pulses at the downhole gauges lag behind the surface pulse. Since data were being acquired only once per second, a highly accurate measurement of this lag cannot be made. But within a 1-sec. accuracy, the lags are as follows:

* Top gauge, 3 sec. lag

* Middle gauge, 4 sec. lag

* Bottom gauge, 5 sec. lag.

From Fig. 5, the pressure amplitudes with the 10-sec. and 20-sec. delays can be compared. For the 10-sec. delay (before the pause), surface pressure amplitude was 107 psi. For the 20-sec. delay, surface pressure amplitude was 114 psi. Amplitudes for two of the gauges are shown below. The middle gauge amplitude is omitted, due to concerns related to the calibration. It is interesting, that a 7-psi increase in pressure pulse amplitude at surface caused a 9-10-psi increase at the downhole gauges:

10 sec. 20 sec.

Top gauge 57 psi 66 psi

Bottom gauge 21 psi 31 psi

At the third pause, the time delay was again increased, this time to 25 sec. Before this change, the surface pressure had increased slightly, to 115 psi. After this change, the surface pressure increased to 116 psi. Pressure amplitude downhole increased 1 or 2 psi.

As a 5-min. time slice, Fig. 6 is similar to Fig. 5, but it is near the end of the pulsation period, instead of at the beginning. From Fig. 4, it would appear that the cement at the bottom gauge was set by this time. However, Fig. 6 shows clearly, that the pressure pulses were still reaching the bottom gauge, though with very low amplitude. At that time, surface amplitude was still 116 psi. Amplitudes at the two gauges were:

* Top gauge, 46 psi

* Bottom gauge, 3 psi.

Once pulsation stopped, pressure at the bottom sensor continued to decrease. The pressure at the middle sensor decreased and then remained flat, and the pressure at the top sensor decreased and then increased again! This was similar to the responses from Well A. We have no explanation for this behavior.


The LSU team has developed a method and software to diagnose the cemented annulus, using a well’s response to CP treatment. [1,2] The diagnostic procedure employs qualitative and quantitative approaches. Qualitatively, a pattern recognition technique analyzes the process of cement setting from the Top Cement Displacement Record (TCDR). In the quantitative analysis, a mathematical model is used to compare theoretical (reference) and recorded TCDRs, and calculate parameters describing the condition of cement slurry in the well’s annulus.

TCDR is a continuous plot of displacement amplitude at the top of the fluid-filled annulus. It is calculated from the actual “compressible volume” of water pumped into, and returning from, the wellhead to the CP unit during treatment. A procedure for generating TCDR data was developed based on automated recording of water level in the CP unit during the treatment. The water record is then corrected for downhole water loss, compressibility of surface installation, water supply, and noise of recording equipment. Then, final TCDR data are used to analyze the well.

In analyzing TCDR patterns, a reference plot is created, using a mathematical model of displacement amplitude vs. time. The plot represents a well’s theoretical response to given slurry properties, well geometry and compressibility, with no water loss and uniform gelation of cement slurry. An example of reference plots is the dotted lines in Fig. 7 for a 7 7/8-in well, with 4 1/2-in casing set at 10,000 ft, and 8 5/8-in outer casing set at 1,500 ft. The well’s annulus is filled with 3,000 ft of 1 10.2-ppg mud column and 7,000 ft of 1 16.4-ppg cement slurry.

The solid line in Fig. 7 represents an anomalous pattern of TCDR, due to gradual bridging in the annulus below the cement top. This may be caused by the combined effects of water loss and filter cake buildup, and resulted in restricted annulus size and partial loss of pulse pressure transmission. Note that the two plots converged prior to stabilization, thus indicating that the bridge developed within the cement column.

The TCDR pattern dominated by water loss in the annular cement is displayed in Fig. 8. Thickening of cement slurry (gel strength development) accelerates under water loss conditions, resulting in exponential reduction of the displacement amplitude. (Note that the two lines in Fig. 8 merge and stabilize, validating input data used for mud properties and open hole compressibility.) Similar exponential patterns of TCDR have been observed in several wells during CP treatment, Fig 9.

Qualitative and quantitative diagnosis of CP treatment in Well D is demonstrated in Fig. 10. Point A corresponds to the maximum depth of treatment. (The ascending curve to the left of point A represents progressive breaking of the initial gel strength in mud and cement columns prior to reaching the maximum treatment depth.) Between points A and B, both cements (tail and lead) are pulsed. The discontinuity at point B indicates the end of tail slurry pulsation and the beginning of transition of the lead slurry. Beginning at point C, the only fluid being pulsed is the drilling mud above the cement column.

Diagnosis.xls software has been used to find the top of cement depth (TOC) from coordinates of points A and C. The calculated value of 6,950 was in very good agreement with the expected TOC position.


Designing a CP treatment for an individual well involves determination of parameters, such as pressure pulse amplitude, pulse cycle duration and the maximum depth of treatment. Interestingly, the three parameters are somewhat dependent on each other. They also would obviously relate to the well properties of cement, mud, rock and annular geometry. Hence, mathematical modeling of pulse transmission becomes a basis for the design.

After a few modeling attempts aimed at pressure wave propagation and other effects of transient pressure, a mathematical model has been derived and used to develop design software. [3] The model describes basic physical mechanisms of the CP process while considering process limitations.

Efficient transmission of small pressure pulses over several thousand feet of non-Newtonian fluids with yield stress could be efficient, if the column yields only at the walls, while the bulk fluid is not sheared. Thus, the model employs the plug flow concept and formulas to describe partial attenuation of pressure in the annulus. Moreover, since the slurry moves only as a plug, its reciprocating motion can be converted to an equivalently slow, continuous motion in the plug flow regime.

One component of pressure attenuation in the mathematical model comes from the need to shear fluids at the annular walls; i.e., pressure at depth must exceed the time-dependent value of static gel strength of the slurry.

During the CP operation, cement slurry is sheared at the walls as it reciprocates upwards and downwards. The displacement is caused by pressure at this depth and controlled by compressibility of the annulus below this depth. The mathematical model of the displacement amplitude is this differential equation:

[sigma]dy/dz + exp(-[cp.sub.o])0.5czPfy(z) = 1 – exp(-[cp.sub.o])[1+cGz)] (1)


y = Displacement amplitude

z = Depth

f = Pulse frequency

c = System compressibility of the well annulus

[p.sub.o] = Top pressure pulse amplitude

P = Slurry constant, dependent on plastic viscosity

G = Slurry constant, dependent on yield stress

The solution to Eq. 1, together with the pressure transmission and system compressibility formulas, constitutes the mathematical model of the CP process. In the model, the depth of CP treatment is determined by assuming that the fluid (cement slurry) becomes motionless at the depth where the transmitted pressure is smaller than that required to exceed the yield stress at the time. This means that: required to exceed the yield strees at the time. This means that:

Where: [Z.sub.t] = Treatment depth;

For z = [Z.sub.t]; p(z) = [I.sub.y](t)

P(z) = Pressure pulse at depth

[I.sub.y](t) = Yield stress at time

The depth of CP treatment versus time is shown in Fig. 11, as the properties of the fluids in Well D are changing for a 100-psi pulse. The design is in good agreement with TCDR from this well, Fig. 10.


The tests make it clear that:

* Pressure pulses are reaching the bottom of the cement column.

* Pressure pulses in the cement are preventing hydrostatic pressure from decreasing significantly.

This research is continuing. CP will be performed on more instrumented wells. Candidate wells in fields with significant gas migration problems are being sought. Models of the CP process are being developed.


Ken Newman is the founder and president of CTES, L.C., an engineering services company affiliated with Varco International. As a recognized authority on coiled tubing, he has authored many technical papers, magazine articles and patents. He holds a master’s degree in mechanical engineering from Massachusetts Institute of Technology and is a registered professional engineer in the state of Texas.

Andrew k. Wojtanowicz is a professor in the Petroleum Engineering Department at Louisiana State University, where he holds the Texaco Environmental Chain He has held faculty positions at New Mexico Institute of Mining and Technology and the Technical University of Mining and Metallurgy in Krakow, Poland. He is a United Nations expert in drilling engineering and has worked as a drilling engineer, drilling supervisor and drilling fluids technologist in Europe and Africa. Mr. Wojtanowicz has conducted research in a variety of subjects related to drilling and well design. During 1992 and 1993, he worked for Conoco Inc. as an environmental research fellow, developing dewatering technology for closed-loop drilling systems. Presently, he is associate editor of ASME’s Journal of Energy Resources Technology. Mr. Wojtanowicz is a registered petroleum and environmental engineer in Louisiana, and a registered petroleum engineer in Oklahoma He holds an MS degree in mining/petroleum engineering and a PhD in petroleum engin eering from the Technical University of Mining and Metallurgy, Krakow.

Brian C. Gahan is a principal technology manager for the E&P Research Group at Gas Technology Institute (GTI), formerly Gas Research Institute, Chicago. Prior to joining GTI in 1991, he served as a reservoir engineering officer for PNC Bank. Mr. Gahan earned a BS degree in Petroleum Engineering from Marietta College and an MBA degree from the University of Pittsburgh Graduate School of Business. He is a candidate for an MS degree in chemical engineering at Illinois Institute of Technology. Mr. Gahan is a member of SPE, American Institute of Chemical Engineers and AAPG, and has served on the board of directors for the Technology Transfer Society (1998-1999).


Habermun, J. P., Sealing gas zones by vibrating cement slurries,” Gas Tips, Spring 1996.

Haberman, J.P., and S. L. Wolhart, “Reciprocating cement slurries after placement by applying pressure pulses its the annulus,” SPE/IADC paper 37619, 1997 SPE/IADC Drilling Conference, Amsterdam. March 1997.

Cooke. C. E., Jr., M.P. Kluck and R. Medrano, “Field measurements of annular pressure and temperature during primary cementing,” SPE paper 11206, 57th SPE Conference. New Orleans, September 1992.

Martin, J. N., J. R. Smith and A. K. Wojtanowiez, “Experimental assessment of methods to maintain bettomhole pressure after cement placement,” ETCE 2001, Drilling paper 17133, Houston, February 2001.


(1.) Kunju, M. K., “Post-treatment diagnosis of cement pulsation wells,” MS Thesis, Louisiana State University, Baton Rouge, Louisiana, May 2001.

(2.) Kunju, M. K., and A. K. Wojtanowiez, “Well cementing diagnosis finer top cement pulsation record,” SPE paper 71387. prepared for Anunal Technical Conference and Exhibition of SPE, New Orleans, September 30-October 3, 2001.

(3.) Chimmalgi, V. S., “Design of sop cement pulsation to prevent gas migration during cementing,” MS Thesis, Louisiana State University, Baton Rouge, Louisiana, May 2001.

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COPYRIGHT 2001 Gulf Publishing Co.

COPYRIGHT 2001 Gale Group

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