Foamed cement solves producing, injection problems

Prentice Creel, Ron Crook
Halliburton Energy Services Inc.
Duncan, Okla.

Three production and injection examples from the Permian basin demonstrate how advanced technology identifies problems that can be treated with foamed cement.

The process involves computer simulation (modeling), log analysis, and tracer surveys.¹

Operators of these wells identified conformance-control problems caused by fractures, interwell communication, and flooding fluid breakthrough.

Background

Permian basin waterflood or CO ₂ floods are usually in dolomite formations. Wells are typically completed in the San Andres, Grayburg, and Clearfork formations.

Problems associated with these floods include:

• Naturally occurring or induced fractures within the reservoirs
• Improper flood practices
• Highly segregated permeability variations both radially and vertically, and injectant quality control.^2-4

Well patterns in these fields include line drives, spot patterns, and other configurations. Placement of wells (Fig. 1 [38,257 bytes]) is typically based on modeling or, in some cases, injection wells have been converted from producing wells that had watered out. ⁵

The unique properties of foamed cement are helpful for solving problems that conventional methods cannot solve. This includes problems with fracture communication (Fig. 2a [119,585 bytes]) and channels between wells. Foamed cement can also be used for modifying fluid injection or production profiles.

Efficient use of water or CO₂ for pressure maintenance and reservoir sweep improvements usually results in producing 40-60% of the recoverable oil in the reservoirs. In many cases, however, enhanced flooding in fields or associated wells is cost-prohibitive because of a near-well-bore loss of integrity or because of poor conditions deep in the formation, away from the well bore.

These deep formation conditions, such as fractures, voids, vugs, and loss of rock, can lead to channeling of injectants and can prevent an effective reservoir sweep.

Natural or induced fractures are also associated with high-permeability streaks. These reservoir fractures and streaks usually have the same orientation. The fractures and their high-permeability orientation determine whether direct communication is possible between offset production and injection wells.

Well patterns then become critical for maintaining pressure and controlling the mobility ratio for an efficient sweep.

Abnormally reduced injection pressures in intervals with high variations in rock stresses, occurring vertically through the pay intervals, often lead to direct communication with offset producing wells. This communication can lead to problems in maintaining an efficient sweep.

The rapid breakthrough of injectants resulting from reservoir variances both vertically and radially cause the injectant to contact less of the reservoir. This rapid response will hamper the maintenance of reservoir pressure, which will decline.

Also, possible leaching and erosion of channels created by the injectant will continually decrease the ability to maintain reservoir pressure. Additionally, damaging effects of injectant precipitation from poor-quality fluids can cause even less injectant to contact the reservoir.

Pressure analysis from surface monitors may be inaccurate because of reduced pressure from channel growth or increased pressure from less-contacted reservoir matrix.

Advanced technologies

The Permian basin case studies required several advanced techniques for identifying problems in specific wells. Once the problems were identified, an appropriate foamed-cement treatment was designed and implemented.

Engineers use a variety of analytical methods to identify problems. These methods, which include computer simulation, log analysis, and tracer surveys, can be mutually exclusive; however, computer simulation benefits from a variety of data sources and analyses.

When designing the most appropriate technique of placing corrective treatments in fractures, engineers often use computer simulation to determine required pressure placement and control. Treatment placement and maximum attainable distance restrict the reservoir's fracture-initiation pressure within the exposed interval.

A number of analyses are performed to obtain necessary information for an accurate computer simulation. For instance, a multirate injection analysis obtains the recommended pressure restrictions to place on exposed intervals during the treatment.

Computer simulation models (both static and dynamic analyses) provide an operator analytical tools for prejob planning, treatment monitoring, and overcoming restrictions imposed on the methods for squeezing a fracture or channel.^{11 12}

While performing analyses such as multirate injectivity, monitoring tagged solutions, or performing velocity shots, engineers can determine problem severity, solution methods, and placement criteria. Channel severity can be determined by comparing the relative rates at which fluid may be injected into the reservoir rock matrix and the channel.

Injection profiles may remain the same over a wide range of injection rates and bottom hole injection pressures. The data obtained from log analyses also can be used in developing a computer model of the well to help predict the effect of different treatments.

Tracer surveys

Tracer surveys can reveal rapid communication within offset wells. A number of agricultural, radioactive, and fluorescent dyes and different methods are used in these surveys.

When these results are included in the computer simulation process or are reviewed with the results of other analyses, engineers can obtain a clearer picture of the problems associated with specific wells.

Foamed cement

Foamed cement squeezes help correct interwell communication problems (Fig. 2b). ^6-10 The high viscosity/thixotropy of foamed cement prevents fluid and gas influx and migration during static or dynamic conditions. The internal energy of foamed cement provides an expandable and compressible fluid that can thoroughly fill channels, vugs, and voids.

Foamed cement has an exceptionally high ratio of strength-to-density and has low fluid loss and low free-water properties.

The inability of foamed cement, even with finely ground particle size, to enter the rock matrix helps reduce formation permeability damage.

Foamed cement placement is based on its viscosity and its capability to remain a true fluid while entering the larger fractured or eroded portions of the formation. For most required amounts, foamed cement can be placed at a lower cost than other options, such as polymers or gels. But foamed cement advantages vary from well to well.

By quickly changing nitrogen concentrations and gas temperatures, engineers can shorten cement setting times and alter viscosity. Once allowed to set, foamed cement develops a high compressive strength, integrity, and resistance to extrusion at the designed density.

Foamed cement is capable of gaining deep penetration in fractures causing communication between wells. It will develop a designed permeability if required or no permeability, depending on its final design density.

Conventional or microfine cements (5-10 micron particle sizes) can be used in foamed cements.

Typical treatments address both near-well bore placements and deep-reservoir placements. Formation barriers can help control fluids when near well bore problems occur, such as casing leaks, channels behind casings, poor zonal isolation, and plugbacks.

Deep-formation placement problems are addressed, such as fracture fill-up (selective) and eroded or leached-out channels between wells.

Example 1

In the first example, foam cement corrected a problem with interwell communications.

The treatment was designed and the maximum pressure was determined from information gained from a tracer survey, a multirate injectivity analysis, and computer simulation.

Treatment approach

Direct communication to an offset producer occurred after acidizing a newly converted injection well in the lower portion of a San Andres zone (Table 1 [64,652 bytes]). A loss of sweep efficiency from the injector occurred while engineers were flooding four other offset wells. Oil production dropped in the producing wells.

A tracer survey with an agricultural dye determined the communication severity from the injector to the offset producer. Engineers determined the volume required to fill and plug the direct channel between the wells.

They discovered that the injected fluid entered the lower open hole portion of the injection interval, and the fluid was channeling into the offset producer 950 ft away. Their calculations showed a channel volume of 11.5-15 bbl.

Pressure drop between the two wells was 1,350 psi, and the bottom hole injection pressure was 2,000 psi with the offset producer being pumped at an estimated bottom hole pressure of 700 psi. Analysis indicated that shutting off this lower portion would benefit the offset producer and would also have a positive effect on the four other producing wells in this pattern.

A computer simulator analysis determined the design of the foamed cement treatment. The design included nitrogen requirements, calculated wellhead pressures, and maximum wellhead pressure to apply throughout the treatment.

During the treatment, a sounder survey monitored the offset producers for communication effects.

Before pumping the treatment, a drillable sliding valve cement retainer was run on a workstring and placed at 4,710 ft, near the casing shoe.

The foamed cement squeeze consisted of 35 sacks of 50/50 microfine cement/micro fly ash foamed with 100 scf/bbl nitrogen followed by 100 sacks of 50/50 premium-plus cement/fly ash foamed with 115 scf/bbl nitrogen. This was injected and displaced to the retainer.

The cement slurries were injected with a foaming surfactant and a foam stabilizer.

Liquid injection rate was 3 bbl/min and the foam rate was 3.6 bbl/min on the lead slurry and 4.3 bbl/min on the tailed-in slurry.

The foamed cement was displaced to within 5 bbl of the retainer before reaching the maximum squeeze pressure. After pulling the tubing out of the retainer, the well was reverse-circulated to remove any excess cement from the tubing.

The well remained shut in for 24 hr before being drilled out and tested for injectivity.

Treatment results

After the wells were cleaned out, tests indicated that the fracture channel was plugged off and the communication was shut off from the injector to the offset producer (Fig. 2c). Injection pressure had increased by 815 psi and a fluid profile showed that the fluid was entering the pay interval.

The designed foamed cement volume exceeded the channel by 2 bbl. This cement retained its integrity into the offset producer.

The squeeze was designed with the excess cement so that it could be determined if foamed cement could be placed and could retain its integrity through the tortuous fractured channel over the 950-ft length between the injection and producing well. Pressure drop across the channel was 1,350 psi.

A follow-up acid treatment with 6,000 gal of 15% hydrochloric acid (HCl) reduced scale damage in the pay and increased the injection rate. The offset production well was then refractured to place a more conductive fracture into the upper portion of the pay interval.

After this work, engineers determined the job's success in sweep modification. The injection rate was set at 200 bw/d at a surface pressure of 400 psi, and the offset well began producing at 25 bo/d and 130 bw/d. After 3 months, production was 25 bo/d and 120 bw/d, and after 9 months production had increased to 40 bo/d and 80 bw/d.

Before the treatment, the offset well production was 0 bo/d and 500-1,780 bw/d. The other four offset producing wells had an increase of 120 bo/d without an increase in water.

Example 2

In the second example, foamed cement corrected problems with gas-cap communications and high-permeability.

Engineers used two computer modeling analyses at the maximum bottom hole injection pressure (BHTP) to design the foamed cement treatment for a large CO₂ WAG flood in the Canyon reef formation.

Treatment design

Operators needed to lower lifting costs, reduce cycling CO ₂, stop injecting outside primary intervals, and improve well bore integrity in a large CO ₂ flood. The focus was on decreasing water production and improving sweep efficiency in the northern part of the unit by squeezing off a large high-permeability, watered-out, gas-cap zone at the top of the reef formation.

Conventional squeeze cementing was initially employed, but proved to be successful only after incurring considerable costs and production downtime. Conventional squeezes required 600-6,000 sacks of cement and 5-40 days to achieve the required results.

Production logs on many wells in the northern part of the unit revealed that 60-90% of the fluid was produced from a large, highly permeable zone at the top of the Canyon reef. However, most, if not all, of the oil was produced from zones below the high-permeability zone.

Injection profiles revealed that most of the injected fluid entered the high-permeability zone. It was also possible that this high-permeability zone had been eroded and leached out by the water and cycled CO₂, causing a highly conductive channel.

To reduce water production and CO₂ breakthrough, the operator chose to squeeze off the problem zone in production wells first and then to squeeze off the zone in some injection wells in the unit.

The staged treatment involved waiting 4-6 hr to allow the cement to gain strength before engineers determined a new injection rate and pressure for the next stage. The process was repeated until the injection rate and pressure were thought to be sufficient to achieve a walking or hesitation squeeze.

The final squeeze consisted of 50-100 sacks of premium-plus cement with 1 lb/sack Latex component and 0.3% friction reducer. The treatment was usually squeezed under a packer or retrievable cement retainer.

Successful squeezes were obtained on some wells; however, the process had to be repeated after drilling out because only the upper part of the zone had been squeezed off.

To determine the maximum BHTP, the operator set a cast-iron bridge plug (CIBP) below the bottom perforation of the squeeze interval, allowed the fluid level to stabilize, and then ran a bottom hole pressure survey.

The first computer modeling analysis was run at the measured bottom hole static pressure (BHSP) to determine the nitrogen requirement (scf/bbl required for a 9-ppg foam density at BHSP).

The second analysis was with the same nitrogen requirement and determined the foam density that would result when the well was squeezed.

A dynamic computer analysis was conducted at BHSP and at maximum BHTP. These analyses were used at the job site to ensure that the maximum BHTP was not exceeded during the job.

During the job, the operators used a chemical injection pump for injecting the foamer surfactant and stabilizer mixture into the suction manifold of the cement mixing unit's downhole pump.

Operators regulated and monitored the foamer-surfactant and stabilizer-mixture injection rate. Nitrogen was injected into the cement through a foam generator connected to the discharge line of the cement pumping unit.

The foam generator produced the required pressure drop while mixing the gas into the cement. Table 2 [132,838 bytes] provides details of the work.

Treatment results

The first well was squeezed to a maximum BHTP with 2 bbl of tail cement left in the tubing. After excess cement was reversed out, the tubing was stung back into the retainer, and 3/4 bbl was pumped.

The well was shut in for about 18 hr. Then, the entire zone was drilled out and tested to 500 psi. The first well has not produced any water and has had CO₂ breakthrough from the high-permeability zone.

This design proved successful, reducing cementing cost by 60-70%. Associated costs and lost production time were also cut considerably.

The treatments enhanced the operator's ability to reduce inefficient cycling of water and CO₂. Six months after the initial squeezes, the offset production wells and treated production wells averaged 22 bo/d/well.

The treatments also reduced lifting costs for a barrel of oil equivalent (BOE) because less water was produced.

Example 3

The third example shows how foamed cement corrected the problems caused by a stratified high-permeability streak in a San Andres waterflood.

Engineers designed the foamed cement treatment with computer simulator analysis programs that determined nitrogen requirements, expected wellhead pressures, and maximum wellhead pressure to be applied throughout the treatment.

Considerations were made for prejob, job treatment, and postjob contingencies.

Treatment design

Operators needed to control the injected fluid from an injection well to offset producing wells in a highly stratified permeability layer within the field.

A small interval in the well was receiving most of the injected fluid. This layer of nonhomogeneous material had extremely high permeability compared to surrounding rock and had almost washed out because of dissolution and erosion by flooding.

Engineers determined that the injection was below the fracturing pressure of the surrounding rock but was virtually unrestricted in its flow toward the offset producing wells. The interval may have had a ^2-5 Darcy original permeability, with the overlying and underlying rock having 0.1-10 md permeabilities.

Placement of a permeable solid formed from the foamed cement would help ensure that injection would still continue into this interval and provide a restrictive pressure barrier. In this manner, the total fluid injected could be maintained at a high rate.

Engineers designed the foamed cement permeability by analyzing the resultant permeability developed by the foamed cement at various densities and pressures. Computer modeling was performed in a real-time analysis while foamed cement was placed. Table 3 [159,353 bytes] provides details of the work.

After placing the treatment, a follow-up drillout of the open hole section took only a few hours.

Treatment results

After circulating the open hole clean, the operator noted that the open hole section had been totally consolidated with its caliper being bit-sized. The well was placed on injection and began taking fluid at the required daily injection rate below fracture pressure.

The final injection test was after follow-up perforating gained entry into selected portions of the open hole.

References

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2. Nevans, J.W., Pande, P.K., and Clark, M.B., "Improved Reservoir Management with Water Quality Enhancement at the North Robertson Unit," Paper No. SPE 27668, Permian Basin Oil and Gas Recovery Conference, Midland, Tex., Mar. 16-18, 1994.
3. Pande, P.K., and Clark, M.B., "Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drilling," Paper No. SPE 27657, Permian Basin Oil and Gas Recovery Conference, Midland, Tex., Mar. 27-29, 1996.
4. Doublet, L.E., Pande, P.K., Clark, M.B., and Nevans, J.W., "An Integrated Geologic and Engineering Reservoir Characterization of the North Robertson (Clearfork) Unit," Paper No. SPE 25594, Permian Basin Oil and Gas Recovery Conference, Midland, Tex., Mar. 27-29, 1996.
5. Cys, J., et al., Lexicon of Permian Stratigraphic Names of the Permian Basin of West Texas and Southern New Mexico, West Texas Geological Society, Midland, Tex., 1976.
6. Harms, W.M., and Febus, J., "Cementing of Fragile Formations Wells with Foamed Cement Slurries," Paper No. SPE 12755, Annual California Regional Meeting SPE, Long Beach, Calif., Apr. 11-13, 1984.
7. Montman, R., and Harms, W.M., "Oil Field Application of Low Density Foamed Portland Cements," Southwestern Petroleum Short Course, Lubbock, Tex., April 1982.
8. "Low Density Foamed Cements Solve Many Oilfield Problems," World Oil, June 1982, p. 171.
9. Aldrich, C.H., and Mitchell, B.J., "Strength, Permeabilities, and Porosities of Oilwell Foam Cement," ASME, Tulsa, Sept. 21-25, 1975.
10. Davies, D.R., Hartog, J.U., and Cobbett, J.S., "Foamed cement-A Cement With Many Applications," Paper No. SPE 9598, Manama, Bahrain, Mar. 9, 1981.
11. Bour, D.L., Creel, P., and Kulakofsky, D.S., "Computer Simulation Improves Cement Squeeze Jobs," Paper No. CIM/SPE 90-113, SPE Joint International Technical Meeting, Calgary, June 10-13, 1990.
12. Creel, P., and Kulakofsky, D.S., "Computer Simulation Program For Cement Squeeze Applications," Southwestern Petroleum Short Course, Lubbock, Tex., Apr. 22-23, 1987.

The Authors