By Calvin Holt, Nilesh Lahoti and Vince Fortier, Tesco Corp
Well cementing is one of the most critical steps of the well completion procedure. However, as the last step in well construction, cementing is sometimes not given the attention it deserves. Various laboratory studies and field experiments have proven that methods like pipe movement during cementing, casing centralization and proper hole cleaning will increase the job quality.
Whether operators are drilling extended-reach wells in prolific shale plays or offshore HPHT wells, well integrity remains the critical concern. Effective zonal isolation using cementing techniques is essential to mitigate risks and nonproductive time associated with leaks, corrosion and contamination.
Although well researched and considered a mature discipline, cement placement in the annulus still has a significant degree of uncertainty. As global regulatory agencies respond to public concerns with drilling operations either in deepwater or unconventional plays, the industry is reviewing well construction best practices to reduce risk.
Despite the industry’s detailed understanding of the advantages of reciprocating and rotating casing during cementing operations, it is applied to less than 10% of wells globally. This mechanical method, although proven to be the most cost effective, remains the least applied. Why?
A proven emerging technology, drilling with casing, developed the modern casing-running tool (CRT). Using tools and drilling engineering methods developed from more than 4 million ft of drilling with casing; rotating casing to ream and while cementing is now a low-risk activity.
Employing the CRT on conventional casing-running jobs delivers a measurably higher degree of probability that casing will reach bottom and effective zonal isolation by cement has been achieved.
The new method of Dynamic Cementation, where pipe movement is maintained until cement begins to set, maximizes the mud-cement displacement process. It can achieve a high-quality completion using a combination of modern cementing software, real-time rig instrumentation and casing rotation/reciprocation with a CRT monitored to planned torque and weight levels while cement is pumped in the annulus.
How does poor cementing occur?
Cement, as an effective sealant, is proven and reliable across several industries, including nuclear. What makes cement in oil and gas wells different? With several variables qualifying a cement job, poor primary cementing occurs all too frequently in drilling for hydrocarbons. This article will focus on mud displacement affecting pipe standoff (SO) and the drilled formation characteristics.
Insufficient Cement Coverage
The most common problem with cementing is inadequate drilling mud removal while cement is being placed around the casing. Pockets of drilling mud or thick filter cake line the wellbore and prevent cement from forming an effective bond. Displacement techniques, such as pre-flush or spacers and centralization, may not be sufficient because conventional cement is not an effective displacement fluid.
Formation gas can invade the cement while it sets. After pumping stops, there is no valid theory to expect additional mud removal from continued pipe movement. However, cement job quality is not dependent solely on mud displacement. While gelling and prior to complete hydration, conventional cement slurry loses its ability to transmit hydrostatic pressure to the formation and fluids from the formation migrate freely into the cement. This forms channels that can create future gas leaks.
Insufficient Cement Height
Drilling highly permeable, depleted zones or naturally fractured formations impairs circulation that can lead to insufficient cement fill or cement fallback in the annulus. As a consequence, cement does not reach its planned coverage height, leaving zones and casing exposed. Over time, leakage and corrosion problems will require remediation.
Barriers to pipe movement
Despite conclusive academic studies, field validations and API recommendations, pipe movement remains a seldom used technique. Even with advances in rig design, top drives, casing drilling and wellbore monitoring, it is estimated that fewer than 6% of wells in the US apply the pipe movement method during cementing. Besides specific well issues that can prevent this best practice, within the land drilling community, status quo practices can be hard to change, and industry knowledge is still lagging.
Myths or misconceptions?
Never pump cement through the top drive
A legacy from the early days of top drive technology, no major manufacturer objects to cement being pumped. As a total amount of volume pumped, cement represents less than 1% of the fluid pumped through the top drive. When objections are raised with respect to abrasiveness, the solids content in drilling muds and their corresponding volume should be of greater concern. This applies to the kelly hose or bottomhole assembly components, as well. Currently, several North American operators insist on their rig contractors pumping cement through the top drive. A large US independent oil company has pumped cement through the top drive on more than 2,500 wells over the past five years, with no undesirable effects.
Casing is not designed to rotate
This is a misconception. Well construction in shale plays require long laterals. This need has pushed the development of high-performance rigs, rotary steerable systems, and the OCTG and their connections. Due to the design of the well pads, long-reaching build sections with high dogleg severity are required to reach the intended targets. This, combined with shallow depths and unconsolidated formations, necessitates a high torque connection that can withstand 25,000 ft-lbs for casing rotation during the cement job.
Casing robustness is well proven by casing while drilling 4 million ft in deviated and horizontal wells, with penetration rates exceeding 500 ft/hr. The technology spawned not only the automated casing-running tool but the development of multi-lobe torque rings, which enable buttress threaded casing to be drilled directionally over several days with no concerns.
OCTG manufacturers have developed connections specifically for drilling with casing.
Centralizers complicate pipe movement
For more than two decades, solid body centralizers floating on the casing have been the standard for rotation applications, and their cost has come down to where they are routinely used in shale wells. It is common practice amongst some operators to rotate the casing to reach bottom and, if hole conditions allow, to maintain rotation while pumping cement until the torque limit is reached.
Swab & surge issue
While neither a myth nor a misconception, reciprocation improperly applied can create swab or surges effects that cause well control problems. In these cases of narrow pressure margins, the casing is lowered carefully at a modeled and planned speed without creating significant surge. If the same parameters are maintained after the pipe is landed, slow reciprocation could occur.
However, when the risk is too high, then rotation (exclusively superior by itself) should be applied. While equivalent circulating density (ECD) will increase with high-speed drill pipe rotation, in cementing operations the low rotational speed of casing mitigates this effect.
Landing casing is risky
Transitioning casing from running to landing in the wellhead is a significant event. Offshore mud line suspension systems or subsea wellheads prevent pipe movement once casing reaches setting depth. On land, with simpler wellheads and sufficient rat hole, pipe movement is acceptable. With proper torque and drag modeling and monitoring, anomalies can be identified while cementing, and corrective action can be taken to ensure buckling does not occur. Reciprocating pipe can be risky for other reasons, such as hanging up, excessive pipe stretch and swab/surge. Although these risks can be mitigated, many times rotation is deemed the superior and safer option.
The more cement the better
In some US states, regulations specify that if gas migration is likely, then a full column of cement in the entire length of the annulus is required. Although well intended, this practice has not always proven effective. The additional cement length increases the hydrostatic pressure initially. Then, as it moves to transition, its sudden loss creates more pressure loss and exacerbates the gas migration tendency. The extra cement column could induce fracturing and lost circulation.
The well can’t afford it
Given the risks and consequences of poor cementing, this should not typically be an issue; however, short-term economic pressure can dictate severe cost control. As operators apply best practices to running casing, they will move from using old, conventional methods to the modern CRT, which requires fewer personnel and enables the removal of the stabber. Any perceived fractional cost increase is countered with additional capability to rotate and ream the casing to bottom.
Once on bottom, the transition to cementing operations is seamless and made more effective by applying pipe movement. This benefit of no additional cost to the operation also contributes to the lack of advocacy for pipe movement.
Dynamic Cementation consists of rotating and reciprocating the casing from the time the cement operation commences until cement is set, as well conditions allow and torque permits. Pipe movement increases the effective volume of drilling fluid moving in the annulus and supplies a mechanical means for breaking the gel strength of immobilized mud or curing cement that otherwise would not be broken by fluid rheology, flow rates or centralization (Griffith, et al., 2007).
Pipe movement during cement placement helps to remove mud that would otherwise be trapped on the narrow side of an eccentric annulus. The basic method is the same as during bottoms-up mud circulation. The following description explains the effect of standoff on mud displacement efficiency during cementing.
The casing is invariably off-center or eccentric, and in a worst-case scenario, the casing can be lying on the low side of the hole. This affects the flow of the fluids in the narrow and wide areas of the annulus (Moroni, et al., 2009). It is defined as standoff, which is a measure of pipe eccentricity.
Standoff can be calculated as:
Standoff = C / A-B
A = Wellbore radius B = Pipe radius
C = Shortest distance between the pipe and wellbore wall
In a static condition when casing is perfectly centered, A – B = C, standoff will be equal to 1 (100%), and if the pipe is touching the wellbore wall since C is 0, standoff will be 0%, as well. In horizontal wells, standoff suffers and is rarely ideal.
When the dynamic conditions of casing rotation and reciprocation are introduced, conventional definitions of standoff have a time element introduced as C is changing constantly as the pipe changes position in the borehole (A), which itself is also not constant due to hole irregularities. These pipe movements can also introduce a hydraulic effect, creating changes to the pressure profile within the wellbore, as well as within the slurry itself.
The primary intent of the cementing operation is to replace the entire mud column with cement, and the efficiency of this task is measured by the following formula (Figure 2):
Displacement efficiency =
Cemented area / Total annular area
Total annular area =
Cemented area + Undisplaced area
As the standoff changes dynamically throughout the pipe movement, the area of highest and lowest flows will change accordingly. These pressure fluctuations will break gel strengths and eventually allow the cement to displace the trapped, static mud around the wellbore, depending on how long the pipe movement continues and the flow rate. When the pipe is rotated, fluid will flow in a circumferential direction, enabling a transfer from narrow to wideside and vice versa.
The correct combination of space rheology and rotation speed can generate local shear stress exceeding that of the drilling fluid and displace it (Ravi et al 2009). Reciprocating can cause lateral casing movement, which alters the flow area and encouraging mud displacement.
Figures 3 through 5 show how the flow area changes as standoff changes. These figures represent snapshots over seconds and minutes of the dynamic cementing operation. With pipe movement, the process will be repeated again and again to optimize the displacement efficiency by continuously changing the standoff until the whole annular area is displaced by cement. To achieve optimal standoff and displacement efficiency, advanced mechanical tools, modeling and monitoring should be utilized to manage pipe movement during cementing.
Suggested levels of Dynamic Cementation
Although pipe movement has its benefits, not all the well geometries allow pipe movement through the entire cementing job. Dynamic Cementation can be categorized into the levels discussed below. The probability of getting better cement bond may increase with the increase in the level employed.
Level 1: Pipe movement while circulating mud before cementing.
Level 2: Pipe movement while pumping cement and set connection torque as limiter.
Level 3: Pipe movement until the optimum torque of casing connection is reached.
Level 4: Pipe movement while pumping displacement fluid until plug is bumped.
Level 5: Pipe movement after the plug is bumped while the cement is setting.
Case study: Level 4 Dynamic Cementation
An independent US-based operator in Fayetteville Shale has been employing pipe movement on every section of casing on every single job. The well in the case study was 10,000-ft vertical depth and a 7,000-ft lateral section. On every joint of casing in the lateral section, 5 ½-in., P-110 with VAM top high torque connections were used with solid bladed centralizers.
Tight spots were experienced during casing running when reaming was performed while simultaneously running the casing. Using the automated CRT saved rig nonproductive time and successfully set casing to the planned depth. After casing was on bottom, pipe movement was performed while circulating the mud for 45 min. Pipe movement was started while cement was pumped into the casing at 60 rpm while the torque was closely monitored. The maximum torque reached during pumping cement was 12,000 ft-lbf. Pipe was continued to rotate while displacement brine was pumped in to the casing at 60 rpm until the torque was reached at 14,000 ft-lbf. The rotation speed was gradually reduced to 45 rpm until the plug was bumped and the pumps were turned off.
Post-cementing calculations showed that employing pipe movement had improved mud displacement efficiency, better cement placement interpreted from the bond logs.
Dynamic Cementer’s toolbox
To realize the benefits of Dynamic Cementation, several mechanical tools are required (Figure 6).
Top drive: The top drive should be considered mandatory as it provides superior hole cleaning in deviated and horizontal wells (Stewart and Williamson 1988). Compared with kelly drive systems, top drives provide the ability to reciprocate and rotate the drill string (or casing) during circulation to improve hole cleaning when conditioning the hole.
Additionally, making connections, back reaming over washed out sections and making frequent wiper trips back to the casing shoe are easily performed. Pumping cement through the top drive is becoming more frequent as it allows pipe movement while cementing and eliminates nonproductive time.
Automated CRT: A direct invention from drilling while casing, the casing drive system (CDS), the original CRT, is attached to the top drive. Besides more efficient casing running, its multiple benefits include eliminating the stabber, preventing stuck pipe and enabling pipe movement while circulating for better hole cleaning and cementing. In recent years, the CRT is becoming recognized as a key tool in cementing operations when moving pipe while cementing is a requirement.
Wireless torque turn sub (WTTS): An integral part of the pipe conveyance system, the WTTS monitors the torque and rotational speed of the casing in torque vs turns and torque vs time or rpm format. The torque sub can be used to check the accuracy of top drive torques used on the driller’s panel. In addition, tension data aids in reaming and reciprocation.
Cement head/swivel: As pumping cement through the top drive is not a universally accepted practice, the use of cementing heads or side-entry swivels is recommended. Also, cementing plug configurations can require the use of plug launching systems. Modern systems allow rotation and reciprocation of casing during cementing; however, they all require additional rig-up time and are pressure limited.
Torque rings: Non-shouldered connections are torque limited and not suitable for severe rotational applications. The Multi-Lobe torque ring (MLT) is a high-performance, low-cost torque capacity enhancement that delivers premium performance to standard API casing. A direct invention from drilling while casing, the ring provides a positive torque shoulder, enabling an additional benefit of increasing torque capacity (termed delta torque). This allows the use of cost-effective API casing and prevents connections from being overstressed. MLT rings are easily field installed and are made from API steel grades.
Centralizers: Proper string centralization can be essential for effective mud removal. Eccentric strings can lead to unequal flow areas on the high and low side of the hole. Because the spacer and then the cement tend to follow the path of least resistance, large mud sections can be left on the low side of the hole. Centralizers are primarily installed on a casing string to provide adequate standoff for primary cementing operations; however, they are also sometimes used to aid in the deployment of casing strings.
To achieve adequate standoff, calculations are performed to determine the number of centralizers, their placement and spacing frequency. Solid type centralizers in horizontal sections are preferred due to their reliability and hole-cleaning benefits while the spring bow type is ideal in vertical sections.
Torque & drag and hydraulic modeling: Accurately predicting tension, compression and torque limits for horizontal completion systems is a standard planning requirement. Torque and drag projections during pipe movement while pumping will require calibrations of the model against field data, as cement-induced effects could alter the frictional characteristics and produce higher-than-planned results.
However, on initial jobs, monitoring casing running and pipe movement both before and after cement placement using current software is adequate to identify downhole anomalies, such as hole cleaning or lost circulation issues. On bottom, the difference in upstroke, downstroke and torque readings will vary depending on the location on the slurry. Trend analysis should be applied to pick up potential problems.
Dynamic Cementation benefits
Dynamic Cementation requires a top drive-enabled rig and automated CRT to allow casing makeup, circulation and pipe movement, the single most cost-effective way to improve zonal isolation (Cowthran, 1982), on a continuous basis. It increases the quality of the cement job by increasing mud displacement efficiency and decreasing pressure loss while cement cures.
A goal of planning for 100% standoff does not reflect the realities of the wellbore despite best efforts in drilling or centralization. In static mode, the casing’s standoff is set, and cement coverage quality relies on fluid rheology and centralization alone. Rotating and reciprocating the casing introduces a dynamic condition, which varies standoff, enabling the constant flow velocity to remove mud channels more effectively from narrow and wide sides of the annulus.
When the pipe is rotated, fluid will flow in a circumferential direction, enabling a transfer from narrow to wide side and vice versa. The correct combination of space rheology and rotation speed can generate local shear stress exceeding that of the drilling fluid and displace it (Ravi, et al, 2009). Another direct benefit is more uniform cement tops, as consistent flow velocity throughout the annulus prevents narrow side lower cement levels.
While both types of pipe movement provide optimum conditions in combination, rotation has been proven to be more effective in removing bypassed mud in horizontal wells. Rotating casing at 15 to 25 rpm provides more pipe movement relative to annular fluids than reciprocating 20 ft/min.
Gas migration in cement is a significant problem that the industry is addressing with a variety of techniques. From gas block slurries to swellable packers, all these methods can be enhanced with Dynamic Cementation. Once the plug is bumped, pipe movement does not have to stop, as cement quality does not rely solely on mud removal. According to Sutton and Ravi (1991), their studies have illustrated a strong correlation between loss of cement column pressure, cement bond and gas migration.
This loss in pressure is the result of adhesion of the slurry to the pipe and borehole caused by slurry gelation plus volume loss from the slurry. Cement bond is decreased when the pressure in the column drops below the adjacent formation pressure while the cement is still in a low-strength deformable state, allowing gas migration.
Dynamic Cementation during the post-cement placement phase transitions to a low-rate pipe movement (LRPM) while the cement column cures. The objective of LRPM is to counteract the continuous reduction of hydrostatic pressure and to maintain low permeability during hydration of cement. LRPM effectively maintains and extends the cement’s initial gel strength while it cures by delaying the pressure loss as it tries to adhere to the pipe.
Its key feature is to delay the development of static gel strength so that the time from 100 to 500 lbf/100 sq ft is as short as possible. This allows the maximum time for the annular hydrostatic pressure to be applied to the formation before the transition to solid cement and reduces the likelihood of gas migration. Pipe movement during the transition period of the cement raises no application problems in equipment or time and is potentially simpler than movement during cement displacement. Rotation speeds of 5 to 10 rpm and 2 ft/min for 5-in. OD casing were shown to be effective. At these speeds, the effect on ECD would be minimal.
Perhaps the most concrete benefit is its low application cost. With casing running and cementing mandatory, the time, planning, procedures and equipment are already a sunk AFE cost. Efficiency-minded operators using a top drive rig can add the CRT to affect a safer, more efficient process to convey casing to bottom the first time, with built-in capability to rotate and ream it to bottom when well conditions dictate.
Depending on well conditions, Dynamic Cementation can eliminate additional or special services related to slurry mixtures, packers, centralizers or additional casing strings. The cost of monitoring key job parameters from the rig data system and cementing provider is already a sunk cost, and no additional personnel are required.
Dynamic Cementation, CDS and MLT are trademarks of Tesco Corp.
This article is based on SPE/IADC 163459, “Dynamic Cementation: A Solution to Well Integrity Problems,” at the 2013 SPE/IADC Drilling Conference, 5-7 March, Amsterdam.