As the oil and gas industry expands exploration into new and more-complex areas, improvements in oil-field cementing equipment and techniques continue to address the problems that arise.
For example, offshore drilling, particularly deepwater drilling, presents numerous challenges that are not encountered in land operations.
The successful placement of cement downhole, in whatever type of reservoir, demands continual research and the development of increasingly specialized tools. Several products designed and developed recently offer sound cementing solutions to operators both onshore and offshore.
This first of a two-part series on modern cement techniques provides information on foamed cement, flexible sealant, elastomeric, and resin-type cement. The conclusion next week discusses cement applications for multilateral wells, variable-viscosity spacers, spacers, and preflushes.
Deepwater prospects represent 25% of the oil reserves in the Gulf of Mexico. Operators who examine and develop these world-class reservoirs face challenges that are unknown elsewhere in the field of oil exploration.
Typically drilled in water more than 1,000 ft deep, deepwater drilling operations are typified by low water temperatures, overpressured waterflow formations, and low fracture gradients to 2,000 ft below the mudline (BML).
Early attempts at deepwater exploration produced a significant number of failures, costing operators an average of $2 million/well. To meet the challenges of deepwater drilling, operators venturing into this area need to manage risk, reduce cycle time, and lower system expenses. They also need proven procedures that help to increase success in all facets of the operation.
Drilling in the world's deeper waters places unique demands on the downhole cementing process. Soft, geologically young formations lie just outside the continental shelf. These formations have been produced by erosion and sloughing of the shelf. Cementing the conductor casing successfully can be complicated by the inferior consolidation properties of these formations (Fig. 1).
The principal disadvantages of using conventional means for setting casing in deepwater environments arise from:
- The failure of water-extended slurries to achieve significant compressive strength.
- The fracturing of young formations by heavyweight slurries.
These factors often lead to lost returns and water flow into the annulus.
Successful deepwater cementing hinges on three factors:
- Optimized mud-management techniques for reducing fluid loss.
- Short slurry transition times.
- Compatibility among the mud and cement, slurry density, and the pore pressure and fracture gradients within the formation.
Failure to satisfy any of these criteria diminishes the likelihood of success.1 New methods of mud management, combined with the use of specially formulated cement slurries, can allow operators in the gulf to set conductor casing effectively in deepwater reservoirs.
Enhanced mud conditions derived from large-scale displacement tests, improved spotting fluid and foam sweeps, and specially designed techniques and slurries produced successful results in 60 of 61 wells studied.
The system for this record involves cementing conductor casing through overpressured waterflow formations as deep as 2,000 ft BML, where the use of conventional cementing techniques did not provide a feasible alternative due to low temperatures and fracture gradients.
One vital key in the string of successes includes the introduction of lightweight, foamed slurry (LFS) developed specifically for deepwater operations. This blend of conventional Portland cement and an ultrafine-grind Portland cement is foamed by nitrogen injection.1
Low-density slurries like LFS can help prevent fractures in shallow, unconsolidated zones like those prevalent in deepwater reservoirs; however, low-temperature environments, also prevalent in deepwater reservoirs, lengthen the transition time in these slurries.
Transition time can be thought of as the interval that extends from the onset of static gel-strength development, when the slurry exerts little hydrostatic pressure, to the attainment of sufficient gel strength needed to prevent fluid migration.
Longer transition times are counterproductive in deepwater cementing because they impede the slurries' initial set condition, diminish resistance to water influx, and allow more time for any influx into the annulus to impair the cement sheath.1
Operators have traditionally used nitrogen-foamed cement to reduce hydrostatic pressure on weak formations. Highly reactive cements, such as ultrafine blends, can be added to these mixes to accelerate hydration, particularly in the 40 to 60° F. temperature range found in the deep gulf waters.
Tests indicate that the ideal transition time in deepwater conditions is less than 30 min, and that the optimal slurry weight ranges from 10.5 to 13.0 ppg. The LFS formulation falls within these parameters.1
The job plan responsible for the deepwater success rate in the Gulf of Mexico has saved operators an average of almost $2 million/well. This plan combines:
- The application of lightweight foamed slurry.
- Mud-management techniques that can reduce fluid loss, condense transition times, and make mud and cement weights compatible with formation pore pressure and fracture gradients.
- An onsite design versatility that can allow for spontaneous slurry density changes without offsite laboratory testing or additional rig-time expense.
The 1997 drilling-completion field program of a major oil company included installation of cement liners in four sidetrack wells deviated 50 to 70° from vertical. In this case, the operator wished to ensure near-complete displacement of the polymer drilling mud and to provide solid zonal isolation in the deviated wellbores. Zonal isolation was especially vital as the well contained two producing horizons.
A comparison of conventional cement and foamed slurry indicated that better results would be possible with the foamed cement. Subsequently, four deviated lateral wells were sealed with foamed cement, after which all lateral sections retained zonal isolation after hydraulic fracturing.
These results, as well as data found in cement bond logs, indicate that the foamed cement was successful in supplying sealing integrity.
History and incentive
Foamed-cement technology, which has been a part of the oil industry for about 20 years, first concentrated initially on solving severe lost-circulation problems in land operations. From those early, limited-application beginnings, the scope of foamed-cement technology has expanded to include the curtailment of water flows in GOM deepwater operations.2
A number of conditions can cause downhole shearing and place undue stress on a cement sheath. These stresses can cause conventional cement to crack both radially and longitudinally. When the integrity of the cement is compromised in this manner, the cement-to-casing and cement-to-formation bond can be severely impaired.
This situation can harm production levels and lead to well failure that may require costly remediation. Other adverse consequences can include hazardous rig and production operations and environmental pollution. In fact, the most common danger is pressure at the wellhead in the form of gas trapped between casing strings.3
Factors contributing to this problem include high-temperature fluids injected into the well or high-temperature fluids produced from the well that raise the temperature at least 100° F. above the slurry's initial setting temperature.
Another factor includes problems associated with relatively high fluid pressure and temperature introduced into the pipestring by testing, perforating, and other procedures that cause the pipe to expand. This expansion, in turn, can generate cracks in the cement or produce failure of the hydraulic seal.
The thermal expansion of fluids trapped within the cement sheath itself can also damage the cement in addition to external forces exerted on the sheath by overburdened pressures and formation shifts.3
The need for a cement capable of maintaining its integrity in spite of these factors led to the development of a slurry infused with a foaming agent and nitrogen or other inert gas. This kind of slurry has shown through laboratory and field tests to possess the elasticity and compressive strength to withstand these destructive forces.
In laboratory experiments, the foamed compositions prevented the production of pressures greater than 1,000 psi at temperatures up to 300° F. This condition occurred in the presence of 60%-by-volume drilling fluid or water when the foam quality of the cement fell between around 25 and 38% (Table 1).
In a recent field study, a foamed slurry was used to cement a liner almost 10,000 ft long in a deep, high-temperature well. Following are the results of tests performed on the cement's compressive strength after setting at:
- 290° F. for 12 hr-106 psi.
- 290° F. for 24 hr-607 psi.
- 190° F. for 12 hr-714 psi.
- 190° F. for 24 hr-1,687 psi (performed under 1,000-psi confining pressure).3
Foamed cement combines three elements: cement slurry, foaming agents, and a gas. Proper blending of the components creates a stable, lightweight slurry with the appearance of gray shaving cream.
Because of the pressure levels, rates, and gas volumes involved, and because nitrogen-pumping equipment provides a reliable gas supply, nitrogen is the preferred gas for most foamed cement operations.
To perform the procedure, personnel mix the foamed cement slurry in a conventional manner with a recirculating cement mixer. As the slurry is being pumped downhole, a foaming agent and stabilizer are injected proportionally into the suction of the pump.
A high-pressure injection of nitrogen is then applied to this mix through a "foam generator" that shears the slurry and creates a stable foam.
Personnel continuously monitor and control the pump rates of the three parameters-slurry, foamer, and nitrogen-to help ensure the correct ratio.
Foamed cement can provide an alternative method for virtually any oil as it can be used to support primary and remedial work in onshore and offshore situations, and in vertical and horizontal wells.
Foamed cement also provides an option for squeezing and plugging jobs in which significantly low fracture gradients are a factor and wells frequently go on a vacuum.
In such operations, computer programs facilitate job design and the interpretation of surface-pressure responses. Although design and execution can become more complex with foamed cement than with conventional slurries, the many advantages of foamed cement can easily offset installation complexities.
A major characteristic that distinguishes foamed cement from conventional cement is reduced weight. Stable foamed cement can be formulated down to a 4-ppg density, a level that would appear to impair its strength value.
Diminished water content and inert nitrogen as filler material, however, can furnish the slurry with a high solids consistency and therefore provide a strength-to-density ratio capable of forestalling formation breakdown, loss of circulation, and post-job cement fallback in primary cementing applications.
Interspersed throughout a well-formulated foamed cement, small (often microscopic), discrete gas bubbles, that neither coalesce nor migrate, can be found.
The compressed bubbles stabilize pressure levels and avert shrinkage during hydration, thereby placing a check on gas migration. The bubbles also improve ductility through the dispersion of applied stress.
As a result, the foamed cement resists shattering during perforation and failure caused by loading and cycling.
The stable gas pockets insulate the wellbore by infusing the cement with a relatively low thermal conductivity that minimizes undesirable heat loss in steam-injection applications and prevents paraffin deposits.
The mud-removal potential of foamed preflushes and slurries, combined with contained expansion and pressure while hydrating, improved ductility, and improved cement-to-pipe and cement-to-formation bonds, contribute to foamed cement's superior long-term zonal isolation capabilities.
Foamed cement slurries can be easily made to withstand temperatures up to 600° F. for use in geothermal applications. The slurries are readily tailored to well conditions through simple adjustments in nitrogen concentrations and can be applied at about one-third the cost of a polymer treatment.
In its various forms, lost circulation, or the leakoff of whole drilling fluid into the formation during drilling or completion work can:
- Impair the mud's efficiency for performing the tasks for which it was designed.
- Impede or stall operations.
- Generate additional expense for the operator.
The numerous materials and systems developed by the oil industry to address this critical problem have met with varying degrees of success.
Downhole flexible sealant (DFS) was designed as a fast and effective means of halting lost circulation in natural and induced fractures, vugs, channels found in weak zones, and over-pressurized regions created by crossflows and underground blowouts.
The DFS can:
- Be used with a broad range of drilling muds and formation fluids.
- Seal multiple weak zones in a single treatment.
- Be pumped through bottomhole assemblies (BHAs).
- Reduce or eliminate trip or waiting time.
- Control crossflows and underground blowouts.
- Strengthen formation integrity to permit the use of heavier muds.
- Remain flexible, as it undergoes reaction, even in the face of swab-and-surge pressures while maintaining the seal in the lost-circulation zone.
- Be specially formulated for environmentally sensitive areas.
Through its three different fluid systems, the DFS suite offers flexibility that allows the use of customized applications. Selection of the proper system is determined by the type of lost-circulation problem, drilling fluid type, the properties of the other, and environmental considerations. Because of the reactive properties of DFS materials, a compatible spacer must be used both ahead of, and behind, the slurry.
Regardless of salinity or pH factors, oil-based flexible sealant systems react quickly when mixed with water-based drilling, completion, and formation fluids (DFS-W). DFS-W can be formulated with kerosine, diesel, esters, mineral oils, or synthetic oils. If additional strength is demanded of the reacted material, cement can be added to the system.
On the other hand, water-based flexible sealant systems react downhole when mixed with such oil-based drilling fluids as diesel invert muds, synthetic-oil drilling fluids, and ester-based muds (DFS-OBM). The OBM formulation is stable in bottomhole circulating temperatures (BHCTs) up to 300° F. for about 2 hr, when cement contamination has not occurred. Moreover, adding a particular stabilizer or surfactant, along with a second surfactant, increases the system's operating range to 415° F.
Mixing a reactive flexible sealant with a water-based activator fluid activates the downhole reaction of this water-based system. This system is recommended in significantly soft or unconsolidated formations requiring a highly flexible, rubberlike sealing material and in regions characterized by dry-gas crossflows.
It is also ideal for areas in which environmental restrictions prohibit the use of nonaqueous fluids and in thief zones with crossflows of dry natural gas.
When a South Texas operator investigated the production potential of a Webb County field, crews were not able to advance the drilling operation beyond the Queen City formation, notorious for lost-circulation problems.
After spending an estimated $150,000 on conventional lost-circulation methods, the operator, in a "last-ditch effort," tried a downhole flexible sealant (DFS). This material allowed the operator to drill to a casing seat 2,000 ft below the Queen City weak zone with no mud losses.
No other system has sealed the Queen City formation so effectively with a single treatment. The DFS operation saved the operator expenses involved with plugging and abandonment, the cost of preparing the wellsite and drilling to the intermediate depth, and the expense of drilling another well to evaluate the production potential that, in any case, would undoubtedly have encountered the same Queen City difficulties.
In another operation, a south Louisiana operator had invested approximately $1 million, including 18 days of rig-time and more than 2,100 bbl of oil-based mud, before using the DFS system to solve the lost-circulation problem. DFS salvaged his investment by facilitating the successful completion of the well.
Several areas in the Permian Basin have been involved in CO2 floods for years. This process involves alternatively injecting CO2 and water into a zone to improve production.
A major operator in the area has reported that during a CO2 injection, a substantial portion of the gas was lost to thief zones. This operator estimated that the losses translated into approximately $10,000,000 over the life of the flood.
These losses are the result of the dissolution of the Portland cement sheath. Cement disintegrates because it converts to calcium carbonate in the presence of CO2 and formation fluids.
The dissolution occurs because of the reaction of the CO2 with the water in the formation, results in the creation of carbonic acid. Calcium carbonate is soluble to acid-water mixes, and the repeated injection of these fluids dissolves the calcium carbonate that results in the loss of zonal isolation.
An elastomeric cement has been used in this application for an operator in southeast Utah.4 Because the elastomeric system is resistant to CO2 attack, the system successfully sealed off the thief zones for more than 2 years, whereas previous conventional cement squeezes had failed as early as 3 weeks after treatment.
High-permeability formations with low tensile strength are extremely vulnerable to shear failure, and the possibility of this occurrence is even greater in the presence of crossflow between zones.
Such problems are especially prevalent in offshore multiwell completion templates where drilling can disturb the balance of forces within the formation and promote the ultimate collapse of cemented casing.
When conventional cement slurry is placed in this type of well, the hydrostatic pressure exerted on the wellbore may exceed the formation's fracture gradient. When this happens, cement is lost into the zone. Lightweight cements are available to treat this problem, but the fracture gradients of certain regions may be too low for lightweight systems.
A wellbore-formation stabilization system (WFSS) composed of a water-based resin and an activator has been developed to prevent shear-failure by reducing mechanical incompatibilities between the formation and the cement. Wellbore characteristics are modified by an alteration of the mechanical properties of the formation.
One of the modifications is an increase in the formation's fracture gradient. Such alterations permit the operator to place conventional cement systems without fracturing the formation or experiencing lost-circulation problems.
The capability of WFSS to penetrate the formation matrix without breaking down the formation has an advantage over conventional cement systems, which do not penetrate the matrix. Conventional systems contain particulate materials that bridge on the formation face. WFSS, a water-thin system, contains no particulates and penetrates the formation easily.
WFSS not only augments tensile strength, Young's modulus, and compressive strength in the formation, but it also minimizes the pore-pressure drawdown at, or near, the wellbore. Each of these effects helps increase the formation's resistance to shear failure. Three resins-high-modulus, mid-modulus, and low-modulus-are available to customize the application.
The high-modulus resin, for example, consolidates drilling mud and filter cake. For wellbore consolidation, the preferred system is determined by the formation permeability.
The high-modulus resin is optimal for high-permeability formations, while the mid and low-modulus resins are useful in low-permeability formations.
WFSS can be used in BHCTs ranging from 50 to 200° F., and the typical treatment volume is 0.25 to 1.0 bbl/ft of formation. The system allows for a broad choice of placements, mechanical properties, and density. Relatively high-modulus drilling fluid and WFSS combinations have been successfully formulated with both water and oil-based muds.
The slurry viscosity itself, or the filtrate derived from these drilling fluid/WFSS combinations, permits the stabilization system to penetrate the formation's porosity and give it mechanical integrity. Upon hardening, the WFSS increases the tensile strength and fracture gradient.
- Griffith, J., and Faul, R., "Mud management, special slurries improve deepwater cementing operations," OGJ, Oct. 20, 1997, pp. 49-51.
- Bour, D.L., et al., " Foam Cement Technology Successfully Solves Problems in Trinidad Offshore Operations," The Brief, Murphy Publishing Inc., Houston, September 1997, pp. 5-8.
- Onan, D.D., Griffith, J.E., and Webster, W.W., "Methods of Preventing Well Cement Stress Failure," U.S. Patent No. 5,696,059, (1997).
- Onan, D.D., Goodwin, K.J., and McPherson, T.W., "Elastomeric Composites for Use in Well Cementing Operations," SPE paper 26572 presented at the SPE Annual Technical Conference and Exhibition, Houston, Oct. 3-6, 1993.
Ronald J. Crook is a senior technical advisor in the Zonal Isolation Cementing Group at Halliburton's Duncan, Okla., Technology Center. Crook is also an instructor for Halliburton's Modern Completion Practices School, Conformance Technology Workshop, and Advanced Engineering-In-Training School. Crook holds a BS in chemical engineering from Oklahoma State University and also has four patents.
David G. Calvert, a former employee of the Mobil Exploration & Producing Technical Center, is a consulting engineer. He joined Mobil in 1979, specializing in acidizing, cementing, fracturing, lost-circulation, and sand-control technologies. Calvert holds a degree in chemistry from Northeastern State University, Tahlequah, Okla.