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Cement is used to hold casing in place and to prevent fluid migration between subsurface formations. Cementing operations can be divided into two broad categories: primary cementing and remedial cementing.
- 1 Primary cementing
- 2 Remedial cementing
- 3 Cement placement procedures
- 4 Well parameters
- 5 References
- 6 Noteworthy papers in OnePetro
- 7 Online multimedia
- 8 External links
- 9 See also
The objective of primary cementing is to provide zonal isolation. Cementing is the process of mixing a slurry of cement, cement additives and water and pumping it down through casing to critical points in the annulus around the casing or in the open hole below the casing string. The two principal functions of the cementing process are:
- To restrict fluid movement between the formations
- To bond and support the casing
If this is achieved effectively, other requirements imposed during the life of the well will be met, including:
- Government regulations
Zonal isolation is not directly related to production; however, this necessary task must be performed effectively to allow production or stimulation operations to be conducted. The success of a well depends on this primary operation. In addition to isolating oil-, gas-, and water-producing zones, cement also aids in
- Protecting the casing from corrosion
- Preventing blowouts by quickly forming a seal
- Protecting the casing from shock loads in deeper drilling
- Sealing off zones of lost circulation or thief zones
Remedial cementing is usually done to correct problems associated with the primary cement job. The most successful and economical approach to remedial cementing is to avoid it by thoroughly planning, designing, and executing all drilling, primary cementing, and completion operations. The need for remedial cementing to restore a well’s operation indicates that primary operational planning and execution were ineffective, resulting in costly repair operations. Remedial cementing operations consist of two broad categories:
Cement placement procedures
In general, there are five steps required to obtain successful cement placement and meet the objectives previously outlined.
- Analyze the well parameters; define the needs of the well, and then design placement techniques and fluids to meet the needs for the life of the well. Fluid properties, fluid mechanics, and chemistry influence the design used for a well.
- Calculate fluid (slurry) composition and perform laboratory tests on the fluids designed in Step 1 to see that they meet the needs.
- Use necessary hardware to implement the design in Step 1; calculate volume of fluids (slurry) to be pumped; and blend, mix, and pump fluids into the annulus.
- Monitor the treatment in real time; compare with Step 1 and make changes as necessary.
- Evaluate the results; compare with the design in Step 1 and make changes as necessary for future jobs.
Along with supporting the casing in the wellbore, the cement is designed to isolate zones, meaning that it keeps each of the penetrated zones and their fluids from communicating with other zones. To keep the zones isolated, it is critical to consider the wellbore and its properties when designing a cement job.
The depth of the well affects the cement slurry design because it influences the following factors:
Amount of wellbore fluids involved Volume of wellbore fluids Friction pressures Hydrostatic pressures Temperature
Wellbore depth also controls hole size and casing size. Extremely deep wells have their own distinct design challenges because of:
- High temperatures
- High pressures
- Corrosive fluids
The geometry of the wellbore is important in determining the amount of cement required for the cementing operation. Hole dimensions can be measured using a variety of methods, including:
- Acoustic calipers
- Electric-log calipers
- Fluid calipers
Openhole geometry can indicate adverse (undesirable) conditions such as washouts. Wellbore geometry and casing dimensions determine the annular volume and the amount of fluid necessary.
The hole shape also determines the clearance between the casing and the wellbore. This annular space influences the effectiveness of drilling-fluid displacement. A minimum annular space of 0.75 to 1.5 in. (hole diameter 2 to 3 in. greater than casing diameter) is recommended. Annular clearances that are smaller restrict the flow characteristics and generally make it more difficult to displace fluids.
Another aspect of hole geometry is the deviation angle. The deviation angle influences the true vertical depth and temperatures. Highly deviated wellbores can be challenging because the casing is not as likely to be centered in the wellbore, and fluid displacement becomes difficult.
Problems created by geometry variations can be overcome by adding centralizers to the casing. Centralizers help to center the casing within the hole, leaving equal annular space around the casing.
The temperatures of the wellbore are critical in the design of a cement job. There are basically three different temperatures to consider:
- Bottomhole circulating temperature (BHCT)
- Bottomhole static temperature (BHST)
- Temperature differential (temperature difference between the top and bottom of cement placement)
The BHCT is the temperature to which the cement will be exposed as it circulates past the bottom of the casing. The BHCT controls the time that it takes for the cement to setup (thickening time). BHCT can be measured using temperature probes that are circulated with the drilling fluid. If actual wellbore temperature cannot be determined, the BHCT can be estimated using the temperature schedules of American Petroleum Inst. (API) RP10B.1 The BHST considers a motionless condition where no fluids are circulating and cooling the wellbore. BHST plays a vital role in the strength development of the cured cement.
The temperature differential becomes a significant factor when the cement is placed over a large interval and there are significant temperature differences between the top and bottom cement locations. Because of the different temperatures, commonly, two different cement slurries may be designed to better accommodate the difference in temperatures.
The bottomhole circulating temperature affects the following:
- Slurry thickening time
- Fluid loss
- Stability (settling)
- Set time
BHST affects compressive-strength development and cement integrity for the life of the well. Knowing the actual temperature that the cement will encounter during placement allows operators to optimize the slurry design. The tendency to overestimate the amount of materials required to keep the cement in a fluid state for pumping and the amount of pumping time required for a job often results in unnecessary cost and well-control problems. Most cement jobs are completed in less than 90 minutes.
To optimize cost and displacement efficiency, the guidelines discussed next are recommended.
- Design the job on the basis of actual wellbore circulating temperatures.
- A downhole temperature subrecorder can be used to measure the circulating temperature of the well. A subrecorder is a memory-recorder device that can either be lowered by wireline or dropped into the drillpipe and measures the temperature downhole during the circulating operation before cementing. The memory recorder is then retrieved from the drillpipe and the BHCT is measured. This allows for accurate determination of the downhole temperature.
- If determining the actual wellbore circulating temperature is not possible, use API RP10B to estimate the BHCT.
- Do not “pad” the actual downhole temperatures measured, and do not exceed the amount of dispersants, retarders, etc. recommended for the temperature of the wellbore. When determining the amount of retarder required for a specific application, consider the rate at which the slurry will be heated.
When a well is drilled, the natural state of the formations is disrupted. The wellbore creates a disturbance where only the formations and their natural forces existed before. During the planning stages of a cement job, certain information must be known about the formation's:
Generally, these factors will be determined during drilling. The density of the drilling fluids in a properly balanced drilling operation can be a good indication of the limitations of the wellbore.
To maintain the integrity of the wellbore, the hydrostatic pressure exerted by the cement, drilling fluid, etc. must not exceed the fracture pressure of the weakest formation. The fracture pressure is the upper safe pressure limitation of the formation before the formation breaks down (the pressure necessary to extend the formation’s fractures). The hydrostatic pressures of the fluids in the wellbore, along with the friction pressures created by the fluids’ movement, cannot exceed the fracture pressure, or the formation will break down. If the formation does break down, the formation is no longer controlled, and lost circulation results. Lost circulation, or fluid loss, must be controlled for successful primary cementing. Pressures experienced in the wellbore also affect the strength development of the cement.
The composition of formations can present compatibility problems. Shale formations are sensitive to fresh water and can slough off if special precautions are not taken, such as increasing the salinity of the water. Other formation and chemistry considerations, such as swelling clays and high-pH fluids, should be taken into consideration. Some formations may also contain elements such as:
- Flowing fluids
- High-pressure fluids
- Corrosive gases
- Other complex features that require special attention
- API RP 10B, Recommended Practice for Testing Well Cements, 22nd edition. 1997. Washington, DC: API.
Noteworthy papers in OnePetro
Stiles, David. 2012. Challenges with Cement Evaluation- What We Know and What We Don’t. https://webevents.spe.org/products/challenges-with-cement-evaluation-what-we-know-and-what-we-don’t