Primary Cementing | What is primary cementing?

(adsbygoogle = window.adsbygoogle || []).push({}); Learning Objectives After completing this topic "Primary Cementing", you will be able to: Define primary cementing and associated terms. Summarize the unique requirements for cementing each of the various casing strings in the context of each string’s purpose and placement in the well. Define primary cementing job design factors. Summarize the major considerations involved in planning a job. List general guidelines for ensuring a successful primary cement job. List the equipment, procedures and areas of application for single-stage, multi-stage, and liner primary cement jobs. State the challenges and special requirements involved in cementing subsea wells and horizontal lateral intervals. Describe inner string cementing and the application of an external casing packer. Describe best practices for operational issues. Introduction https://youtu.be/hOoLxsl9cHc The most common cementing operation is primary cementing, which involves displacing the slurry down the inside of a string of casing, around the bottom of the casing shoe, and up the outside of the casing string, where it can harden into a competent cement sheath (Animation 1). Primary cementing overview Animation 1 https://youtu.be/AuACo3VwGqo (adsbygoogle = window.adsbygoogle || []).push({}); Primary cementing is performed immediately after casing is run into the borehole. The details and placement techniques may vary depending on conditions, but the process is nearly the same regardless of the purpose or size of the casing string. The large majority of cementing operations are primary cementing jobs. There are three general types of primary cementing techniques: Single-stage cementing: The most common procedure is the single-stage primary cement job using the two-plug system. Cement is pumped down the casing between two rubber wiper plugs which are used to clean the interior wall of the casing and to prevent contamination of the cement by the drilling mud. Multi-stage cementing: Most multi-stage cement jobs are performed to alleviate the high hydrostatic pressure exerted on formations by a long column of cement. However, the availability of low density cement slurries have made multi-stage cementing much less common than it used to be. Liner cementing: Liners are casing strings that extend into an open hole section of the wellbore but are hung off the previous casing string instead of being tied back to the surface. The cement slurry is pumped through the drill pipe and into the top of the liner through specialized equipment. This course discusses each of these types of cementing operations. Because primary cementing procedures are driven in large part by the well interval in which a particular casing string is being placed, the course begins with a review of the hole intervals and general casing classifications, followed by a review of the common data needed to design typical job. (adsbygoogle = window.adsbygoogle || []).push({}); Casing Program Overview (adsbygoogle = window.adsbygoogle || []).push({}); Casing programs are an integral element of the well planning and design process. In general, casing programs reflect a “bottom-up” or “inside-out” design process. For example: The design process starts with the innermost tubulars: the tubing string and accompanying downhole production or injection equipment, which is designed for the anticipated formation pressures and production or injection rates. Moving outward, the production casing or liner is designed to accommodate the tubing string(s). Continuing outward, the design moves progressively toward the surface, with the intermediate, surface, and conductor casing. Figure 1 illustrates a relatively simple casing program as described above, along with a complex program that involves setting multiple contingency and intermediate strings. Figure 1: Casing programs Casing Specifications and Performance Properties Casing is specified in terms of: Length Outside diameter and wall thickness, which determine the casing’s inside diameter and weight per unit length Grade, which indicates the tensile strength and minimum yield stress of the material, and is based on the chemical composition of the steel and the heat treatment methods applied Connections, which refer to the type of thread or coupling used to join individual lengths of casing The length, diameter, and wall thickness define both the volume of the casing and the volume of the annulus between the casing and borehole or between concentric casing strings. These volumes determine how much cement slurry, spacer, wash fluid, or displacement fluid are needed for a particular job. Casing specifications result in a casing string exhibiting certain mechanical properties: Burst strength: The minimum internal pressure that will cause the casing to rupture in the absence of external pressure and axial loading Collapse resistance: The minimum external pressure that will cause the casing to rupture in the absence of internal pressure and axial loading Tensile strength: Pipe body: The tensile force that will cause the casing to exceed its elastic limit Joint strength: The tensile force that will cause failure in the casing connection It is important to consider the load conditions that cementing operations might place on casing, and to determine whether these loads could exceed the casing strength. (adsbygoogle = window.adsbygoogle || []).push({}); Casing TypePurposeConductorProtects very shallow formations from drilling fluidsPrevents erosion or caving of surface sediments or the sea bed below the rigEnables fluid returns to the flow line or mud lineProvides support for subsequent casing stingsSurfaceSeals off problem formations found at relatively shallow depthsIsolates fresh water formations and prevents their contamination by drilling fluid or fluids from deeper formationsIs the first casing string employed to control subsurface pressuresPermits the safe drilling of shallow gas zones below the casing shoeIntermediateProtects shallow formations from the high mud gradientsAllows changes in mud typeSeals off problem formationsProductionMaintains wellbore integrity and pressure control in the pay zoneIsolates zones through selective perforationConducts formation fluid to wellboreProtects well and subsurface environment in case of tubing failureFacilitates repair or replacement of production equipmentTable 1: Casing Types Conductor Casing The conductor is the shallowest string of casing, (Figure 2) and the first one set in the well. Setting depths can be as shallow as 20 ft and is usually less than 300 ft. Outside pipe diameters can range from 18 to 42 inches, with 30 inches being a common size. Figure 2: Conductor casing The hole for the conductor can be drilled or the conductor can be jetted into position or driven into the sediment using a pile driver. When the conductor hole is drilled or jetted, the pipe can be cemented into place by pumping cement and observing cement returns at the surface. In cases where the pipe is driven into the ground, it may be left uncemented. Functions Conductor casing serves the following purposes: Protect very shallow formations from drilling fluids. Prevent erosion or caving of surface sediments or the sea bed below the rig. Enable fluid returns to the flow line or mud line. Provide support for subsequent casing stings for the diverter system used before installation of a blowout preventer (BOP) stack. Cementing Considerations for Conductor Casings (adsbygoogle = window.adsbygoogle || []).push({}); Conventional Onshore Wells Typical slurries for conductor casing applications at conventional onshore wells include API Class A, C, G, or H with 2% calcium chloride as an accelerator. Lost-circulation additives such as sand, gilsonite, and cellophane may be added without significant effect on the slurry-thickening time or compressive strength. Where lost circulation is severe, a thixotropic cement can be used. When the cement cannot be circulated back to surface, a “top-out” slurry may be pumped into the annulus from the surface through small tubing (this is called “grouting”) on top of the primary cement. Offshore Deepwater Wells Installing a conductor at offshore locations in deep water can be complicated by abnormally high saltwater flow formations, and the existence of weak formations that can fracture and cause loss of cement returns. A typical arrangement would be to drive a 30-inch OD pipe to 200 feet below the mud line and then cement a 20-inch OD conductor string by pumping cement through the drill pipe until cement returns back to the ocean floor via the annulus. However, at deepwater locations low subsea temperatures slow the cement hydration process, which allows water or gas influx from shallow formations to form channels that destroy cement sheath integrity (Griffith, 1995). Successful techniques for deepwater conductor cementing include: Circulating a good mud that contains fluid loss control additives and exhibits low gel-strength development as the conductor hole is drilled and before running casing Using a high-viscosity spacer Incorporating rigid centralizers on the conductor Using nitrogen-foamed cement with accelerators to reduce hydrostatic pressure on weak formations and hasten the onset of hydration in the 40 to 60°F temperatures prevalent in the deep US Gulf waters Using ultrafine/hollow ceramic bead slurries that are lightweight, but also high-compressive strength Surface Casing (adsbygoogle = window.adsbygoogle || []).push({}); The surface casing is run after the conductor pipe (Figure 3), and cemented at depths ranging from a few hundred to a few thousand feet. The actual setting depth depends on the proposed total well depth, the competency of the shallow formations encountered during drilling, and state regulations regarding protection of freshwater zones. Surface casing diameters can vary from 7 inches to 26 inches. Figure 3: Surface casing Functions Surface casing serves the following purposes: Seals off problem formations found at relatively shallow depths, such as lost circulation zones, unconsolidated formations, heaving or sloughing shales Isolates fresh water formations and prevents their contamination by drilling fluid or fluids from deeper formations Is the first casing string employed to control subsurface pressures, and must be strong enough to support a BOP stack and provide a solid anchor for a casing head to hang off subsequent casing strings Permits the safe drilling of shallow gas zones below the casing shoe Cementing Considerations for Surface Casings A common problem with cementing surface casing is placing the required height of cement in the annulus (often to the surface) when the hydrostatic pressure of the slurry exceeds the fracture pressure of formations within the surface hole. Low-density slurries and foamed cement are options for solving this problem. Operators who are cementing surface casing strings also must contend with borehole washouts in unconsolidated intervals. This leads to uncertainty in determining the actual hole volume and the need to design significant excesses into the planned slurry volumes. An open hole caliper log measures hole diameter, and can be useful in reducing this uncertainty. Intermediate Casing (adsbygoogle = window.adsbygoogle || []).push({}); One or more intermediate casing strings (sometimes referred to as “protection” strings) may be required below the surface casing (Figure 4). Setting depths can vary from 1000 to more than 17,000 feet, with outside diameters ranging from 6-5/8 inches to 16 inches. Figure 4: Intermediate casing Intermediate casing is usually run to the surface and, like the surface casing, anchors and connects the BOP stack with a higher pressure rating for subsequent drilling operations. However, in certain deep wells intermediate “contingency” liners may be run. Often the intermediate string requires the largest volume of cement of any string in a well and is also the string through which the longest period of drilling time occurs. Functions Intermediate casing serves the following purposes: Protects shallow formations from the high mud gradients needed in deeper intervals (while allowing for mud weight reduction in case of pressure regression in deeper formations) Allows changes in mud type Seals off problem formations such as hydrocarbon-bearing, abnormally pressured zones, fractured formations, low pressure gradient formations, expanding shale, salt, or anhydrite during the drilling process One or several intermediate strings may be necessary to maintain borehole integrity at greater drilling depths and to separate the hole into workable increments for drilling. Cementing Considerations for Intermediate Casings Unlike conductor and surface casings, additives such as friction reducers, fluid-loss additives, and retarders are more commonly required for intermediate slurries. Where the annulus is small, friction reducers allow lower pump pressures and reduce the chance of losing fluids in a lost-circulation zone. Fluid-loss additives prevent slurry loss into lost-circulation zones and dehydration in the annulus caused by permeable zones, and also improve bonding results. High-performance, lightweight cements permit intermediate strings to be cemented in a single stage, although multistage cementing may be necessary if even this approach fails to accommodate weak formations or if it is imperative that a specific hydrocarbon-bearing layer be well isolated. Multistage cementing is more common in intermediate strings than other casing strings. Production Casing (adsbygoogle = window.adsbygoogle || []).push({}); Production casing or liner strings are the final “layer” of protective tubular elements making up a well Figure 5. Production tubing, through which hydrocarbon fluids flow, is installed inside the production casing. In rare cases flow is through the production casing itself. Typical production casing OD sizes are 4-1/2to 9-5/8 inches. Setting depths can vary from 1500 feet or less to more than 25,000 feet. Figure 5: Production casing Functions Production casing serves the following purposes: Maintains wellbore integrity and pressure control in the pay zone. Isolates zones through selective perforation. Conducts formation fluid to wellbore. Protects well and subsurface environment in case of tubing failure. Facilitates repair or replacement of production equipment. A production liner performs these same functions without the expense of running casing all the way back to surface. Cementing Considerations for Production Casing (adsbygoogle = window.adsbygoogle || []).push({}); Production casing is normally run and cemented through the zone to be produced and then perforated to permit communication from the reservoir to the wellbore. The slurry used to cement production casing must be designed to keep the producing zone under control during the cementing process while minimizing filtrate loss to the formation that could reduce permeability. Fluid loss rates should be kept less than [latex]\tfrac{100\, mL}{30\, min}[/latex], preferably in the [latex]\tfrac{50\, mL}{30\, min}[/latex] range and even less in the case of high-pressure, high-temperature wells. The general guideline for adequate zonal isolation by the cement across the producing formation is 1,000 psi compressive strength and less than 0.1 millidarcies of water permeability. When bottomhole temperatures exceed 230 °F, compressive strength can be maintained by adding 30% to 40% by weight silica flour to the dry cement. Combination Strings In certain cases it may be advantageous to vary the casing size within a single string of casing, with a smaller diameter casing on the bottom connected by a crossover swage to a larger diameter casing on the top. This configuration, also known as a tapered string, may be used when there are wider diameter tubing components higher in the well (such as gas lift mandrels, a subsurface safety valve, or multiple tubing strings for a multiple zone completion). (adsbygoogle = window.adsbygoogle || []).push({}); Example Casing Program: Marcellus Shale Well (adsbygoogle = window.adsbygoogle || []).push({}); A typical Marcellus Shale well casing program is illustrated in Figure 1. Figure 1: Marcellus Shale well casing program In this example, the upper hole sections are constructed as shown in Table 1: SectionTop of casing, feetBottom of casing, feetTop of cement, feetHole diameter, inchesCasing outside diameter, inchesCasing inside diameter, inchesRemarksConductorSurface50Surface242019 SurfaceSurface250Surface17 1/21615.01Protect shallow aquifers from contaminationIntermediate (1)Surface700Surface14 3/411 3/410.772Drilled through various coal seamsIntermediate (2)Surface2000 10 5/8 Table 1: Upper Hole Sections, Marcellus Shale Well (adsbygoogle = window.adsbygoogle || []).push({}); Following this, a 7.875 inch hole is drilled out of the second intermediate string. Depending on the depth of the Marcellus, this portion of the well is drilled to a depth of several thousand feet before an angle is built and the hole is deviated to horizontal - generally at about 6000 to 9000 feet TVD. The horizontal section may be maintained for several thousand more feet through the productive formation. (Wells can have measured depths of 13,000 feet or more). Challenges to getting a good primary cement job in the horizontal section of a Marcellus well include fractures and faults, doglegs, washouts, drill cuttings, and borehole cavings. To attain adequate pipe standoff (at least 67% based on a computer simulation), two centralizers are spaced on each casing joint along the entire horizontal interval. Then, to ensure adequate cuttings removal before cementing begins, four open-hole volumes of conditioned drilling mud are circulated after the casing is run to bottom. (adsbygoogle = window.adsbygoogle || []).push({}); Well Data Requirements for Cement Job Design (adsbygoogle = window.adsbygoogle || []).push({}); For a cement job to be successful, the engineer must determine these important parameters: Volume of cement required Setting time required Ensuring that the cement will get into position Ensuring that the cement will not damage the formation To answer these questions, three categories of information are needed: Well depth and hole/casing dimensional data Wellbore environment: pressure regime, fluid chemistry, rock mechanics Wellbore temperature regime These data will determine the cement properties required and the additives to be used to achieve them, the slurry and spacer volumes to be pumped, and the flow regimes. Well Depth and Dimensional Data The data required include: Vertical depth Measured depth Angles and azimuths of deviation Type of casing string (such as full string or liner) Casing string size and weight Open hole size variation over the length of the drilled section Depth and deviation are important because no well is exactly vertical and the key to proper centralization of a casing string is knowledge of where deviations in the wellbore will cause the casing to lie against the wellbore wall and require centralizers. In principle, the wellbore size is determined by the drill bit diameter; but in fact a wellbore is rarely cylindrical. The variation in hole shape will affect the cement volume calculations, the displacement mechanics and the need for centralizers. Openhole caliper logging devices are run into the hole prior to running the casing string to get an accurate picture of the hole size variation with depth (Figure 1). Figure 1: Example of a six-arm caliper logging tool, its log showing the deviation from gauge over a 50 foot interval, and a 3D representation of wellbore trajectories and hole size variation using downhole data and specialized software (adsbygoogle = window.adsbygoogle || []).push({}); The greater number of arms on the caliper tool, the better the accuracy of the interpretation. Calipers are typically run with various logging tools, but a minimum of four arms are needed for a good measurement. Hole size can also be measured ultrasonically with a rotating sensor. Caliper logs are not typically run in the large diameter surface hole sections of a well bore, where the calculation of cement volume is typically boosted by the addition of a excess amount of cement to ensure adequate annular coverage. The amount of excess required is based on local experience. With the increased use of logging-while-drilling (LWD) or measurement-while-drilling (MED) tools, the size of the open hole can be determined from acoustic measurements and transmitted in real time during drilling and pipe tripping operations. Specialized software can be used to display this information or convert it into required fluid volumes. Knowing specific wellbore characteristics - for example, the presence and location of pay zones, water aquifers, salt sections, fractured zones, and shale intervals that can expand into the wellbore - is critical in cement job planning. Most important are the expected formation pore pressures and formation fracture pressures along the wellbore. Pore pressure data will have been developed in the well planning phase of the project, or collected during drilling and logging operations. Where MWD has been used, this information may be quite detailed along the well path. The fracture pressure gradient (Figure 2) is important to understanding the limit beyond which cement hydrostatic head will fracture any given formation within the borehole, causing the cement to be lost. This information will have been developed for the drilling process, but may need to be revised based on indications of lost circulation during drilling. (adsbygoogle = window.adsbygoogle || []).push({}); Figure 2: (A) General depiction of subsurface fracture pressure gradient relative to the normal hydrostatic gradient or pore pressure, and the overburden or lithostatic gradient, and (B) data from a specific field showing the transition from normally pressured sediments to over-pressured sediments Similarly, understanding the formation pore pressure profile, including sections of the hole that may be underpressured or overpressured is important to predicting where cement slurry properties will be critical to maintaining good hole conditions or avoiding high filtrate loss. Temperature Regime When designing a cement job, the bottomhole circulating temperature (BHCT) and the bottomhole static temperature (BHST) must be considered in addition to the temperature difference between the bottom and top of the cement column. The BHST is the temperature of the undisturbed formation at the final depth in a well. This temperature is measured under static conditions after sufficient time has elapsed to negate any effects from circulating fluids. Tables, charts and computer routines can be used to predict BHST as a function of depth and geographic area, or a temperature log can be run. Log temperatures measured 24 hours after mud circulation may be considered static. The BHST is important for predicting the rate of compressive strength development. The BHCT is the temperature that the cement slurry will encounter as it is placed in the well and the temperature that must be used for slurry thickening time tests. This temperature will determine what types of retarders or other additives are needed. It is lower than the BHST due to the cooling effect of mud displacement. The BHCT can be calculated using temperature schedules published in ISO 10426-1-2001 and API 10A. However these standards are only good for typical well conditions and not for deepwater wells or unusually hot wells. Computer simulators that model the physics of heat transfer under dynamic pumping conditions are widely used. These programs consider all of the well parameters affecting BHCT including well geometry, fluid rheology, pump rate, pumping time, and surface injection temperature and are validated using measured downhole temperatures. Using these tools an engineer can predict slurry temperatures at various points in a well over the pumping and displacement time period. For example, Figure 3 shows the modeled temperature profile as a function of depth in the casing and annulus for a long horizontal well (vertical depth 6,900 ft and measured depth 27,900 ft after one complete cycle of mud circulation immediately before cement placement (510 minutes). The temperature at the bottom of the hole is 167 °F. (adsbygoogle = window.adsbygoogle || []).push({}); Figure 3: Modeled temperature profile as a function of depth The temperature history plot (right) shows the BHCT over time, including the 72 °C (162 ºF) measurement at 510 minutes. The annular and inside casing (tubular) BHCTs are identical, as would be expected. The BHST, also shown in the geothermal profile curve in the plot on the left, is 85 °C (185 ºF). However, the BHCT predicted by the API/ISO schedule is only 53 °C (127 °F), significantly lower than the modeled number. If a retarder had been chosen based on this prediction rather than the more accurate modeled number, the actual thickening time in the well could have been much shorter due to the higher temperature, with potentially serious results. The temperature difference between the top and bottom of the cement column is also important. For example, cement slurry that has been retarded to ensure adequate time for placement at a given BHCT may remain liquid when circulated back up the annulus to a shallow depth in the well. If adequate compressive strength cannot be obtained at the top of cement (TOC) location, it may be necessary to execute the job in stages. (adsbygoogle = window.adsbygoogle || []).push({}); Slurry Design Considerations (adsbygoogle = window.adsbygoogle || []).push({}); Slurry design is an iterative process. A formulation that is expected to meet the required performance criteria is created based on experience and local or regional databases. Laboratory testing is performed to verify predicted results and refine the design. Testing of the final design with field samples is essential to ensure that the slurry to be pumped is consistent with the slurry designed in the lab. One of the most important considerations in cement slurry design is density. Slurry density is dictated by: Fracture gradient Expected pore pressures API class of cement chosen Overall well objectives including economics In the past, higher density cement slurries were created to develop rapid compressive strength. Today however, high compressive strength cements can be designed at very low densities through the careful control of cement particle sizes. Each well offers a range of acceptable hydrostatic pressures. A worst-case scenario involves identifying the zone of highest pore-pressure and the zone of lowest fracturing pressure (Figure 1). Figure 1: Density range between the fracture pressure and pore pressure Normally, the weakest zones in a well are exposed to the highest pressure immediately before the completion of the job (before the top plug lands). At this point, the longest column of slurry will be in the annulus and friction pressure will be at its highest level. This is generally considered to be the time with the highest likelihood of a formation breakdown. Conversely, the worst-case scenario from a well control standpoint occurs when the fluid of lowest density in a cementing program (typically a chemical wash pumped ahead of the cement) passes a zone with high pore pressure. In the absence of any other considerations, the maximum allowable downhole density possible without causing fracturing should be chosen for the cement slurry - at least 1 [latex]\tfrac{lbm}{gal}[/latex], preferably 2 or 3 [latex]\tfrac{lbm}{gal}[/latex], heavier than the drilling mud. Pumping excess cement to ensure adequate annular fill is a common practice when the borehole size is uncertain due to washouts. However, if the borehole is closer to gauge than expected, this excess can cause cement to be circulated to a higher point in the annulus than planned for, and if weak zones are present the higher hydrostatic pressure can lead to a fracture, loss of cement, and potential loss of the well. Similarly, if a low density wash or spacer is pumped to a higher than expected point in the annulus, the resulting drop in hydrostatic pressure can lead to influx and loss of well control. Slurry Design Example (adsbygoogle = window.adsbygoogle || []).push({}); A North Sea well was drilled out of the surface casing prior to cementing the 9-5/8 inch intermediate casing at a depth of 6,476 ft (1,974 m). The well was nearly vertical, and nearly in gauge with an open-hole diameter ranging from 12.2 to 13 inches (31 to 33 cm), although a few washed out sections between 900 m and 1,175 m depth in the Barremian formation enlarged the hole to up to 18 inches (46 cm) as shown in Figure 2. Figure 2: Wellbore profile for North Sea well cement job example The Albian formation is a high pore pressure water zone that must be properly isolated, but weak formations below the Albian prevent the use of normal density cement slurry. There are salt/evaporite formations along the open hole section. A very good bond across the casing shoe is critical because the mud weight must be increased from 9.8 [latex]\tfrac{lbm}{gal}[/latex] to 17.1 [latex]\tfrac{lbm}{gal}[/latex] for drilling the lower 8-1/8 inch hole out of the 9-5/8 inch casing. One option would be to perform the cement job in two stages, allowing for placement of high density slurry across the Albian aquifer zone. This would be expensive, however, requiring significantly more rig time and the potential need for remedial cementing. The decision was made to perform a single stage cement job using lightweight lead slurry and a short, normal density tail slurry to provide high strength at the casing shoe. The known geothermal gradient of [latex]\tfrac{1.5\, ^{\circ}F}{100\, ft}[/latex] ([latex]\left (\tfrac{2.7\, ^{\circ}C}{100\, m} \right )[/latex]) was used to calculate a static temperature at the shoe of 176 °F (80 °C). The bottom hole circulating temperature (BHCT) calculated from API tables is 123 °F(50 °C). Circulating the conditioned drilling mud at a density of 9.8 [latex]\tfrac{lbm}{gal}[/latex] (1,150 [latex]\tfrac{kg}{m^{3}}[/latex]) at a rate of 6.3 [latex]\tfrac{bbl}{min}[/latex] for about 2.5 hours lowered the annular temperature at the shoe to the BHCT. A computer simulation showed that the annular temperature profile after this circulation was about 50 +/- 2 °C from about 750 m to the casing shoe (Figure 3). The temperature near the Albian aquifer of concern was approximately at the geothermal gradient of about 47-48 °C. Figure 3: Depth profile for North Sea well cement job example (adsbygoogle = window.adsbygoogle || []).push({}); The portion of the cement slurry pumped first, the lighter-weight lead slurry, is a 11.5 [latex]\tfrac{lbm}{gal}[/latex] density slurry with the following additives: Dispersant to facilitate mixing of a high-solids slurry Fluid loss additives to avoid bridging off across the permeable zones Salt (18% by weight of water) to help alleviate problems in the evaporate intervals Retarder to achieve a thickening time of 7-8 hours. The job is expected to take 4 to 5 hours to complete, so with a 50% safety margin, the minimum thickening time should be 6 to 8 hours The tail slurry, pumped second, is designed to be heavier with a density of 15.9 [latex]\tfrac{lbm}{gal}[/latex], the same dispersant, fluid loss additives, salt, and a retarder that provides for slightly less thickening time than the lead slurry (about 5 to 6 hours). Because the annulus (9-5/8 inch OD casing in a 12 to 13 inch hole) had a relatively small clearance, achieving turbulent flow could result in high effective circulating density (ECD) and risk breaking down weak formations. The best option for ensuring good mud removal was determined to be a combination of spacers and chemical washes. A computer simulation program was used to calculate optimal slurry rheology. The fluid volumes, properties and job schedule are shown in Table 1. Fluid Pumped or ActivityVol. (Bbl)Annular distance (ft)Density (lbmgal)Rate (bblmin)Stage Time (min)Elapsed Time (min)Cum. Vol. (bbl)Start Job Chemical Wash26.8 9.64.06.66.626.8Spacer119.9 11.08.01521.6146.8Drop bottom plug 526.6146.8Lead slurry522.55,86911.55.398.2124.8669.2Tail Slurry53.760715.96.78132.8722.9Drop top plug 5137.8722.9Mud400.0 9.88.050187.81122.9Mud93.1 9.85.317.5205.31216.0Mud66.3 9.84.016.6221.91282.3Mud55.4 9.82.720.7242.61337.6End Job Table 1: Job schedule and properties for North Sea well cement job example (Nelson and Guillot, 2006) (adsbygoogle = window.adsbygoogle || []).push({}); The job began with pumping a 27-barrel chemical wash at 4 barrels per minute followed by a 120 bbl high viscosity spacer at a rate of 8 bbl per minute, the highest pump rate that would be reached during the job. Next, the bottom plug was dropped, followed by the lead slurry, which was planned to rise all the way to the surface in the annulus. After the entire job was pumped, the tail slurry was calculated to extend 607 feet above the casing shoe in the annulus, while the lead slurry would extend from the top of the tail slurry to the surface, another 5,869 feet. The lead slurry was pumped at a rate of 5.3 [latex]\tfrac{bbl}{min}[/latex] while the tail slurry was pumped a bit faster at a rate of 6.7 [latex]\tfrac{bbl}{min}[/latex]. Total cement pumping time was just under two hours. The top plug was dropped behind the tail slurry, followed by a 9.8 [latex]\tfrac{lbm}{gal}[/latex] mud was used to displace the cement to bottom. The mud was pumped at rates that decreased in stages, beginning at 8 [latex]\tfrac{bbl}{min}[/latex] and ending at 2.7 [latex]\tfrac{bbl}{min}[/latex], to ensure that the plug was bumped safely. The overall job time was about 4 hours. A simulator was used to assess annular pressures at the casing shoe over time and dynamic frictional pressure relative to fracturing pressure along the entire borehole (Figure 4). The minimum and maximum pressures were within the limits of pore pressure and fracturing pressure, ensuring a successful job. Figure 4: Simulator output for (a) annular pressure at the casing shoe and (b) dynamic pressure over the wellbore profile (adsbygoogle = window.adsbygoogle || []).push({}); U-Tube Effect (adsbygoogle = window.adsbygoogle || []).push({}); The pump rate may be unable to keep the casing full of cement during the early part of the job. The falling cement will push fluid down the casing and up the annulus, creating a situation where efflux from the annulus is greater than the slurry volume being pumped into the casing. Eventually the situation will correct itself as hydrostatic pressure equilibrium is approached. But the problem may occur several times as, for example, a lighter density wash is displaced around the casing shoe and fills the annulus at the bottom of the well. https://youtu.be/SVAgyRYRyUw U-tube effect These events can be misinterpreted as a loss of circulation or a loss of well control and the potential for U-tubing must be considered in the job design. Algorithms exist for accurately simulating U-tube effects. (adsbygoogle = window.adsbygoogle || []).push({}); The check-valve assembly fixed within the float shoe or float collar prevents flow back of the cement slurry when pumping is stopped (for example when the second wiper plug is dropped). Without the check valve, the cement slurry placed in the annulus could U-tube, or reverse flow back into the casing. https://youtu.be/Sk0ZogLbC7Q (adsbygoogle = window.adsbygoogle || []).push({}); Elements of a Successful Cement Job (adsbygoogle = window.adsbygoogle || []).push({}); Designing a cement job is an iterative and collaborative process. The collaboration takes place between the operating company and the service company and begins at the well planning stage. As the drilling process continues, new data are collected and checked against the preliminary expectations for the wellbore environment. Planning the final cement job for each casing string involves: Establishing final objectives for the well, including economics Studying problems in offset wells Identifying likely pressure regimes Planning for health, safety and environmental impacts and issues Determining the final well geometry, deviation, and static and dynamic temperatures Selecting the appropriate equipment and materials Finalizing a slurry design Selecting a mud displacement strategy Selecting the appropriate washes and/or spacers Finalizing procedures and pumping schedules with assistance from computer simulations But even a well-planned and executed cement job requires that: The wellbore be drilled true to gauge and in a manner that will minimize the difficulty of removing the drilling mud and cuttings ahead of the cement slurry Quality control procedures are followed during cement and additive transport, storage and mixing operations The cement slurry design is tested in the laboratory to make certain it will perform as required The mixed slurry on location is tested to make certain it performs as designed when field cement and mix water is used Pipe centralization, reciprocation and rotation plans are understood by all cementing team members Real-time recordings of pump rate, surface pressure and fluid density (Figure 1) are compared with simulation predictions (adsbygoogle = window.adsbygoogle || []).push({}); Figure 1: Cementing job report showing surface pressure, pump rate, and fluid density (adsbygoogle = window.adsbygoogle || []).push({}); Single-Stage Cementing Process (adsbygoogle = window.adsbygoogle || []).push({}); When the casing is in place and conditioned mud has circulated long enough to remove any gelled mud from the annulus, circulation must be stopped long enough to load both cement plugs into the cementing head. Generally, one of the following sequences are followed: Drop bottom plug, pump spacer, pump cement, drop top plug, displace cement with mud, or Pump wash, drop bottom plug, pump spacer, pump cement, drop top plug, displace cement with mud, or Pump wash, drop bottom plug, pump cement, drop top plug, displace cement with mud A two-plug primary cementing operation is illustrated in Animation 1. https://youtu.be/WxjLh58TXAA As a general practice, the bottom wiper plug should be placed between the fluids of highest density difference, as long as a sacrificial volume is tolerated for the contamination between the other fluid interfaces (such as spacer and cement). To avoid contamination of the cement by the mud-contaminated spacer in situations where that could lead to retarded development of compressive strength, the bottom plug may be dropped within the last portion of the spacer in a sequence: Pump wash Pump nearly all of spacer Drop bottom plug Pump last portion sacrificial volume of spacer Pump cement slurry Drop top plug Displace cement with mud (adsbygoogle = window.adsbygoogle || []).push({}); Dropping the wiper plugs should not take longer than the time needed to open and close the valves at the cement head. Cementing heads and top drive cementing equipment have wireless tools for remotely executing these operations with minimal time loss. If pumping is stopped for more than five minutes, downhole fluids could develop gel strength. This could require additional pressure to restart fluid movement, a situation that could in extreme cases lead to formation fracturing downhole, or the creation of pockets of gelled mud that could inhibit uniform cement placement. A bottom plug is not recommended for use with cement slurry containing large amounts of lost-circulation material or with casing that is badly rusted or scaled internally. Such debris may collect on the edges of the ruptured diaphragm of the bottom plug, bridge off the casing, and prevent total displacement of the slurry, jeopardizing the success of the job. Because of U-tubing, the top of the cement inside the casing may actually be a considerable distance below the top wiper plug when it is dropped. Depending on the cement volume and density, the cement may already have rounded the casing shoe when the plug is dropped. The rate at which the cement is displaced into the annulus is not necessarily the same as the rate of pumping into the casing head. Once U-tubing has ceased and continuous flow is restored into the casing and out of the annulus at the surface, displacement continues until the top wiper plug is “bumped.” The pump rate is usually reduced near the end of the displacement to avoid a sharp pressure increase when the plug reaches the collar. Upon bumping the plug, if pressure holds, the casing can be pressure tested (provided that the plugs and collar have been selected to permit this test without breaking). Surface pressure is then released and the casing is observed for back flow that would indicate the float equipment is not functioning properly. If no back flow is observed, the line is left open during the waiting-on-cement (WOC) time period. This is the time allotted for the cement to set and develop sufficient compressive strength. If the float collar does not hold, the mud returns must be pumped back into the casing, maintaining pressure on the casing until the cement sets. However, it is important to bleed off any excess casing pressure that develops (due to thermal expansion of the cement in the annulus). If this is not done a micro-annulus may form between the casing and cement sheath because of expansion and contraction of the casing (Figure 1). (adsbygoogle = window.adsbygoogle || []).push({}); Figure 1: Cross-section of well with three strings of casing and conductor pipe shows cement coverage. Evidence of mud-contaminated cement is observed as well as micro-annulus. When the cement has started to set, the normal practice of landing the casing in the wellhead can be performed. The casing will be hanging from the rig elevators and after the cement has set, the BOPs are lifted from the casing head and suspended from the substructure. Slips and the casing pack-off assembly are then set between the casing and casing head. A new casing head is then flanged to the previous one and the BOPs are attached before the next section of hole is drilled. (adsbygoogle = window.adsbygoogle || []).push({}); Multiple-Stage Cementing (adsbygoogle = window.adsbygoogle || []).push({}); Multiple-stage cementing has typically been used in downhole formations that cannot support the hydrostatic pressure of a long column of cement. Today, specialized cement formulations make it more practical to carry out single stage cementing operations in many such formations. In some situations however, stage cementing remains an option. These can include: When cement is not required between widely separated intervals When the upper portion of an annulus must be cemented with a higher-density cement system In deep, hot holes where time to pump the desired quality and quantity of cement is limited and thus slurry pumpability is best maintained by reducing the total volume to be placed in an interval during any particular pumping operation In horizontal wells where the bend radius of the well requires cementing There are essentially three multi-stage techniques: Regular two-stage cementing, where the cementing of each stage is a distinct operation Continuous two-stage cementing Three-stage cementing The second and third techniques are rarely employed. Multi-stage cementing adds to the execution time of a cement job and, because most cementing heads cannot accommodate the preloading of all of the devices needed to carry out a multi-stage operation, the cement head must be opened during the procedure, adding to the complexity. A casing string set up for multi-stage cementing includes one or more stage cementing collars designed to be opened and closed by pressure-operated sliding sleeves. These collars provide a port for cement to be circulated to the annulus without going around the casing shoe. First Stage Cementing Operations (adsbygoogle = window.adsbygoogle || []).push({}); The mixing and pumping of spacers and slurry during the first stage of a multi-stage cement job are essentially the same as a single stage job except there often is no bottom wiper plug. After pumping the slurry, the first stage wiper plug is dropped and lands in the float collar (Figure 1). In some situations, operators displace the first stage cement slurry with a completion fluid, leaving the casing below the stage collar filled with completion fluid. Figure 1: Two-stage cementing process If the plan is to cement the entire casing string, the first stage cement slurry volume should be calculated to extend above the stage collar in the annulus. If not, the second stage cement slurry can fall through the less dense annulus fluid and result in a poor second-stage cement job. In some cases a cementing basket is run on the outside of the casing to prevent the cement slurry from falling. Second Stage Cementing Operations Immediately after the first stage is completed, a opening “bomb” is dropped to engage the internal structure of the stage collar. When the bomb is seated, pump pressure (usually 1,200 to 1,500 psi) is applied, shearing the retaining pins and allowing a sliding sleeve to move and uncover ports to the annulus. In some cases (such as horizontal wells in which there is no gravity to make the bomb fall), hydraulically operated stage collars open when pump pressure is applied against the first stage plug. When the ports open, they permit the first stage cement sitting above the stage collar to be circulated up the annulus and the well is circulated via the ports until the mud is properly conditioned and the first stage cement has set. This is important to ensure that weak zones along the first stage section do not break down when the hydrostatic column of the second stage cement is imposed. In cementing the second stage, spacers and slurries are mixed and pumped in the same manner as a single stage job. The closing plug is dropped and pumped to seat in the stage collar. At this point, at least 1,500 psi (10.5 MPa) of pump pressure is applied to close the ports in the stage collar. Pressure is then released and the cement is allowed to reach its final set strength. Most second stage cementing procedures are performed using a low-density slurry to allow circulation to the surface. Normal-density slurries are used when a high-pressure zone or aquifer must be thoroughly isolated. The density of the tail slurry of the second stage can be increased to enhance the cement strength around the stage collar, which is most likely to be the weakest point in the casing string. Continuous Two-Stage Cementing Operations (adsbygoogle = window.adsbygoogle || []).push({}); If the situation requires that the cement be displaced without stopping to wait for a bomb to be seated, the two-stage operation can be accomplished in a continuous mode. In this case, which is rarely used, a wiper plug follows the first stage, and displacement fluid behind the plug places the first stage cement outside the annulus. A stage collar opening plug is pumped, followed immediately by the second stage cement slurry and the closing plug. Displacement of the slurry will cause the opening plug to seat, the collar to open, and the slurry to be displaced into the annulus. Final closure of the tool after seating of the closing plug is the same as with conventional two-stage cementing. Three-Stage Cementing Operations This option is rarely applied, because it significantly increases the time required and the complexity of the operation, increasing the potential for malfunctions to threaten the success of the cementing operation. In this case, both a second-stage collar and a third-stage collar are included in the casing string, and two sequences of sealing plugs, bombs and closing plugs must be dropped for the job to be completed. (adsbygoogle = window.adsbygoogle || []).push({}); Liner Cementing (adsbygoogle = window.adsbygoogle || []).push({}); A liner is assembled in the same manner as conventional casing and lowered into the well, including float equipment and centralizers. A liner hanger is placed at the top of the liner to enable its connection to the larger casing string from which it will be hung. A liner is hung under tension, which prevents it from buckling under its own weight. The liner is usually run into the well on drill pipe, using a retrievable setting tool that is removed with the drill pipe once the liner has been cemented in place. Mud cake and gelled mud removal, always a priority in cementing, can be particularly difficult in the case of liner cementing due to what are commonly smaller annular spaces. For example, a 5-inch OD liner hung from a 7-inch casing will have a maximum clearance of 9/16 inch (1.4 cm) if perfectly centered. Special small clearance centralizers that also permit liner rotation during cementing are used to help alleviate eccentric liners. Liner movement during cementing is generally considered to be critical, despite concerns about premature unlatching from the setting tool, casing parting, swabbing of the pay zone, or wellbore sloughing and annulus bridging. Also, adequate volumes of washes and spacers are even more important in liner cementing than with conventional casing strings. Smaller annular spaces make it easier to achieve turbulent flow at lower pump rates, helping to support efficient mud removal ahead of the slurry. Liner Cementing Procedure A liner cementing head is installed on the top of the drill pipe with a manifold for holding pumpdown darts and ball, analogous to the wiper plugs pumped down the casing and held in the casing cementing head (Figure 1). As with conventional casing, a top drive cementing head system can also be used to enable pipe movement during cementing. (adsbygoogle = window.adsbygoogle || []).push({}); Figure 1: Liner cementing heads, integral and top drive versions Drilling mud is conditioned and circulated as with any cementing procedure. After the cementing lines are rigged up and tested, the preliminary chemical wash and spacer is pumped down the drill pipe (Figure 2). A bottom wiper plug may or may not be used ahead of the spacer or slurry. After the slurry is mixed and pumped into the drill pipe, a pumpdown dart is dropped and displaced with mud. The dart passes through the setting tool and latches into the hanger (or the previously dropped wiper plug), after which pumping pressure rises to about 1,200 psi (8.4 MPa). The pressure rise is an indication that the drill pipe has been displaced and the liner is full of cement slurry. Figure 2: Liner cementing procedure with no bottom plug The pressure causes shear pins to break, releasing the pumpdown plug to continue through the setting tool and down through the liner. When the internal volume of the liner has been displaced and the cement slurry is all within the liner/borehole annulus, the plug seats in the float collar and the pressure rises again, indicating that the job is completed. Once the job is completed, the setting tool and drill pipe are pulled out of the hole, leaving the cement to cure. (adsbygoogle = window.adsbygoogle || []).push({}); Cementing Subsea Wells (adsbygoogle = window.adsbygoogle || []).push({}); The cementing procedures for offshore wells drilled from jackup rigs or stationary platforms are similar to primary cementing operation on land rigs. Subsea wells drilled from a floating drilling vessel are cemented with a system somewhat similar to that used for cementing liners, except that because the larger wiper plugs cannot fit through the drill pipe, both the plugs and plug release system are integrated into an assembly within the casing below the casing hanger (Figure 1). Figure 1: Single-stage subsea cementing system The cementing head on a floating drilling vessel is made up to the drill pipe which is used to land the casing string. The cementing head contains a launching ball and dart used to release the larger plugs in the casing. Offshore cementing heads are top-drive compatible, so the drill pipe and casing can be rotated during cementing. (adsbygoogle = window.adsbygoogle || []).push({}); After conditioning and circulating the mud and pumping washes or spacers - just before pumping the cement slurry - a bottom plug launching ball is released from the cementing head. It moves through the top plug and seats in the bottom plug held in the plug release assembly within the casing hanger. A 100 to 275 psi pressure increase behind the ball shears the connector pins and permits the bottom plug to travel down the casing until it bumps on the float collar at the bottom of the casing string, with the cement slurry behind it in the casing. Extra pump and hydrostatic pressure extrudes the ball through its orifice seat and cement displacement continues around the casing shoe. Once the cement slurry has been pumped, the top plug launching dart is released at the surface. It seats in the top plug and the resulting increased pump pressure shears the holding pins, causing the second plug to move from the plug release assembly like the first one. When all of the cement slurry has been displaced the plug bumps on the float collar. There are a number of challenges in cementing subsea wells, particularly those in deep water. These include: The added hydrostatic pressure from the additional distance above the subsea assembly and the smaller degree of separation between pore pressure and fracture pressure The low temperatures at the seafloor and within the shallower subsurface formations and the impact on cement slurry characteristics The presence of relatively shallow water-producing or gas-producing zones that must be cemented quickly and effectively The complications introduced by the extended reach or horizontal wellbores commonly employed to develop offshore reservoirs from single subsea well templates A variety of specialized cementing tools and procedures have been developed to deal with these challenges. (adsbygoogle = window.adsbygoogle || []).push({}); Cementing Horizontal Intervals (adsbygoogle = window.adsbygoogle || []).push({}); Cementing casing strings in extended reach or horizontal intervals presents special challenges. These include: Efficient cleaning of the low side of the borehole of both cuttings and mud Formation of free-water phase in cement slurry on high side of annulus Maintaining borehole stability during cementing Effective centralization of the casing Impact of increased drag within the horizontal interval on hole conditions Typically, complex cement jobs are designed using sophisticated software to model the process. The software takes into account factors such as density, friction, setting time, geometry, and chemistry. In addition to normal good cementing practices, follow these additional recommendations for cementing horizontal laterals (Matson and Bennet 1990): (adsbygoogle = window.adsbygoogle || []).push({}); Pay special attention to the development of good annular velocity (180 to 300 feet per minute) for the angle build and horizontal sections of the wellbore during mud conditioning and circulating. Maintain a standoff of 67% or greater by using software to optimize centralizer spacing. When the casing is in place, circulate the hole two to three times with a target of 95% of an accurately calipered annular volume being circulated. Use fluid marker materials (such as oats, nut shells, dyes, or beads) while drilling the horizontal hole section (at about every 100 ft), on clean-up trips, and when the casing is in place to provide a comparison of how much of the calculated (calipered) hole is circulating. Plan the total cement job fluid-density sequence to reduce gravity effects by displacing the top wiper plug with the lightest fluid possible without causing safety problems. Lighter displacement fluid inside the casing will improve pipe buoyancy and allow the centralizers to be more effective. Employ some form of pipe movement to enhance mud removal - rotation and, if possible, reciprocation-depending on rig and tool considerations. Normally, rotation speeds from 10 to 22 rpm are adequate. Use a spacer with a density about 0.5 [latex]\tfrac{lbm}{gal}[/latex] greater than the mud density, but less than the cement density, and a volume designed to allow 10 minutes or more of uncontaminated contact time under turbulent conditions. Design cement slurry to control free water at bottom hole conditions, maintain fluid-loss within a range of 30-50 ml/30 min, and control gel strength development so the slurry remains fluid with little gelation up to the limit of its pumpability. (adsbygoogle = window.adsbygoogle || []).push({}); Special Primary Cementing Methods (adsbygoogle = window.adsbygoogle || []).push({}); Several cementing methods designed to manage special situations deserve a brief description. Inner-String Cementing Cementing large-diameter casing sometimes requires some special considerations. Such casing, which has a relatively large cross-sectional area, is subject to being pumped out of the hole if significant pump and hydrostatic pressure at the casing shoe acting on this area exceeds the buoyed weight of the casing. Large casing can also be floated out of the hole if the weight of the casing and the mud in the pipe do not exceed the buoyancy provided by the annular column of cement after it is displaced. Inner-string or stab-in cementing is a fairly common practice for large-diameter casing. The string is cemented through drill pipe inserted into a special sealing sleeve in the shoe (Animation 1). https://youtu.be/Ztnyq4crVBI External Cement-Filled Packer When zonal isolation is particularly critical, external cement filled casing packers can be utilized. Extra-long (20- or 40-ft) elastomer-sheath covered inflatable packers can be run as part of the casing string. One packer (or more) is landed across the productive zone to be perforated and the primary job is completed conventionally (Animation 2). https://youtu.be/Piqu4hkldsg (adsbygoogle = window.adsbygoogle || []).push({}); When the initial slurry displacement is complete and the top plug is bumped, but before the cement sets, pressure is increased to open shear-pin controlled valves in the packers, and additional cement is pumped into the packer elements to expand them tightly against the borehole wall. This “inflation cement” is pumped down the casing between the first top wiper plug and a special second top wiper plug. After curing, the cement-filled packer and the casing joint mandrel on which it is run are perforated by conventional methods. Two such cement-filled packers can be used effectively to straddle a productive interval for zone isolation. External cement-filled packers offer these advantages in primary cementing: Mud channels across the producing zone are avoided completely by the squeezing of any remaining mud or mud cake from the packer rubber-formation interface. The producing formation is supported by the pressure-set cement packer and unconsolidated zones cannot dilate or “flow” with a production pressure differential. (adsbygoogle = window.adsbygoogle || []).push({}); General Operational Considerations (adsbygoogle = window.adsbygoogle || []).push({}); There are a number of important factors to consider in obtaining a good primary cement job, most of which have been described in this course. Additional factors that special emphasis are discussed here. Slurry Volume Because of the difficulty in gauging large open holes, surface casing hole volumes are rarely known precisely. The volume of cement required to fill the annulus can be based on historical experience, but if this information is unavailable, an excess slurry volume of at least 50% of the surface hole callipered annular volume should be pumped. If there is evidence that the upper portion of the hole is widely out of gauge, this can be boosted to 100% or more. This number can exceed 300% for the top section of some deepwater wells. Even when the callipered volume is believed to be accurate, an excess volume of up to 50% is often pumped for the surface casing. For casing strings run after the surface casing, where there is an accurate callipered hole volume, a 10% excess in slurry volume is sufficient. When one is estimating the hole volume based only on bit size, at least a 50% excess factor should be applied. As with the surface hole, regional experience can be a guide. In some areas, regulatory requirements dictate how far the top of the cement must be above the uppermost pay zone, and this will determine slurry volume. Three hundred to five hundred feet of cement above the top of the pay is typical for many locations. Displacement (adsbygoogle = window.adsbygoogle || []).push({}); It is important to achieve complete displacement of the cement slurry, not only to obtain good isolation but also to avoid the need to drill out a large volume of tail cement from the casing after the cement job. Complete displacement also provides the opportunity to effectively pressure test the casing shoe. If the plug does not bump when expected, signaling complete displacement of the slurry, an additional volume of displacement fluid should be pumped before stopping the operation (generally equal to the capacity of the two joints of casing typically run between the shoe and float collar). The displacement volume calculation is based on casing capacity tables from casing manufacturers. Sometimes these capacities do not accurately account for the true internal diameter of the casing delivered. For example, the internal displacement volume of 9,843 feet of 9-5/8 inch, 47 [latex]\tfrac{lbm}{ft}[/latex] casing is 720.5 barrels according to the tables. The actual volume required would be 735 barrels, a 14.5 barrel difference, if the internal diameter of the casing run were only 1% larger than the nominal value. Careful operators systematically gauge either all casing joints or a statistically significant number of joints while the casing is on the pipe rack. Another potential cause of displacement volume error is failing to account for the compressibility of the displacing drilling fluid, especially when using oil-based muds. Increasing pressure acts to compress fluid volume with depth, while increasing temperature acts to expand fluid volume. The appropriate compressibility of oil-based drilling muds should be obtained from the mud company to make certain that what could be a several barrel error is not introduced. Temperature Knowing the bottomhole circulating temperature (BHCT) is vital. Temperature affects nearly everything about a cement slurry: density, viscosity, flow regime, U-tubing behavior, and friction pressure. The BHCT can be obtained through logging, circulation of temperature probes, or computer modeling, but its accurate determination is critical. When knowledge of cement strength development time is key, it is important to know how long it will take for the cement slurry temperature to reach the static temperature. Only a temperature simulation model can provide this information. The surface ambient temperature, as well as the temperatures of the dry cement and mix water, influences the slurry mixing temperature and thus the slurry temperature profile as it is pumped downhole. Also, when dry cement is added to mix water the hydration process generates heat. If all of these variables are not taken into account, waiting-on-cement (WOC) times may be too long or too short, and the performance of additives, particularly accelerators, can be misjudged. Casing Movement (adsbygoogle = window.adsbygoogle || []).push({}); Casing movement - reciprocation, rotation, or both - improves the chances of obtaining a good cement job. Reciprocation is difficult to carry out from floating rigs or in highly deviated wells. Rotation, however, is always possible if the wellhead and rig designs are chosen to accommodate it. Generally speaking, such choices are recommended. When conventional casings are cemented, the highest torque load is generally reached when the leading end of the cement reaches the shoe. The casing connections must be designed to withstand such torque loads if casing rotation is to be implemented as it should. Begin pipe movement and mud conditioning immediately after the casing is on bottom. If wall cake and cuttings in the mud returns have either virtually stopped or declined rapidly in volume, repeat scratching movements. Casing movement should begin at the start of circulation and continue throughout the circulation period. With reciprocating scratchers, the pipe is commonly moved through a 20-ft stroke, with a two-minute interval for the cycle. If rotating scratchers are used, the pipe is rotated as slowly as possible, usually between 10 and 20 rpm. Bonding (adsbygoogle = window.adsbygoogle || []).push({}); Good zonal isolation depends not only on effective placement of the cement within the annulus, but also on effective bonding of the cement to both the formations along the wellbore wall and the outer surface of the casing string, or in the case of an annulus between two casing strings, two casing surfaces. Achieving a certain compressive strength does not guarantee that a good bond has been achieved. There are two types of bonds that must be considered: shear bonding and hydraulic bonding. The strength of the shear bond mechanically supports the pipe in the hole and is defined as the force required to initiate pipe movement in a cement sheath divided by the cement/casing contact surface area. Hydraulic bonding blocks the migration of fluids along the pipe/cement or formation/cement interface. The strength of the hydraulic bond is defined as the pressure required to initiate leakage at either of these interfaces. Both of these bond strengths can be measured in the laboratory for a variety of cement formulations, casing surface conditions, and formation surfaces. For zonal isolation, hydraulic bonding is more important than shear bonding. Cement-to-casing shear bond strength tends to increase non-linearly with cement compressive strength. Also, a thin coating of mud at the cement-pipe interface results in a loss of both shear bond strength and hydraulic bond strength. Oil-based mud is more detrimental than water-based mud. Higher shear bond strengths are observed when the pipe surface is roughened by rust, wire brushing, or sandblasting to remove mill varnish. Pressurizing the casing during the setting process is detrimental to shear bond development. For cement-to-formation bonding, higher bond strengths are obtained against permeable formations because the cement is dehydrated via filter loss, resulting in a higher strength cement. Avoiding cement contamination To prevent cement slurry problems in critical situations, two bottom plugs may be required, one ahead of and one behind the spacer fluid pumped ahead of the cement. The spacer pumped ahead of the cement will not remove the thin film of mud on the inside of the casing. When the top plug is pumped behind the slurry, it will collect this mud film and push it ahead, contaminating the tail end of the cement (Figure 1), which is the portion that will be key to obtaining high strength cement at the casing shoe. If two bottom plugs are pumped to frame the spacer, this film can be effectively removed. Figure 1: Lack of second bottom wiper plug between space and cement slurry (after Owsley) (adsbygoogle = window.adsbygoogle || []).push({}); Casing Quality Control Following a few guidelines regarding casing quality control can help to ensure that issues unrelated to the cement or pumping operation do not endanger the success of the cementing job. First, tally all casing on the rack, being careful to count, number, and “rabbit” (check the internal ID gauge) all casing joints. Check all casing threads for debris or damage. Additionally, check the threads on any crossover equipment for proper thread type and cleanliness. Identify all joints by weight and thread type, and place them in proper order for running into the hole. This is particularly important in combination strings. Space the landing joints out so that there is no trouble installing the cementing head from either the stabbing board or rig floor after the entire casing string is run. Verify that float collars and float shoes are in good working condition. Check the operational features if differential floating equipment is used. Measure dimensions and prepare stage cementing equipment separately. If necessary, use thread-locking compound or tack weld on all field makeup connections of the float equipment, plus one or two joints above. General “Good Cementing Engineering Housekeeping” Also important is following these general guidelines regarding engineering preparedness. Follow all safety procedures including pre-job safety checklists, job safety analysis, pre-job communications (toolbox talks). Provide all service personnel involved ample notice of the start of casing operations, so that the correct people are on the job site and prepared before this time. Ensure that the cementing team leader and the person on the pump throttle understand the importance of the pumping rate to the success of a job. Maintain a log of operations that includes time, density measurements, mixing rate, displacement rate, wellhead pressure, operation in progress, volume of fluid pumped pump strokes per minute and total strokes, in addition to what is recorded by sensors and displayed on the computer screen. Hold variations in cement density close to limits and calibrate density measuring equipment is calibrated before the job starts. Be aware that changing over from slurry pumping to displacement fluid pumping takes seconds, not minutes. (adsbygoogle = window.adsbygoogle || []).push({}); Assignment Primary Cementing (adsbygoogle = window.adsbygoogle || []).push({}); Cement Job Design: Part A: For the production string of the Assignment well, it has been determined that the pressure required to pump the slurry up the annulus (Annular Pressure Loss) is 550 psi. You are using a Class G cement containing fly ash (density 14.5 ppg) at 8,000 ft TVD. The fracture pressure is 0.8 [latex]\tfrac{psi}{ft}[/latex]. What is the maximum allowable pump pressure to push the slurry up the annulus without fracturing the formation? Part B: You are designing the mud weight for the production string of the Assignment well, and you are given the following pressure chart for the well. The casing string goes to 8000 TVD, and you are given the task of designing the job. Assume a negligible annular pressure loss. 1) Can this job be pumped in a single stage, or are two stages required? 2) What cement weight(s) are acceptable for this job? Solution Part A Solution: The fracture pressure of the well is [latex]0.8\ \tfrac{psi}{ft}\ \times 8,000\ ft\ =\ 6400\ psi[/latex]. The hydrostatic pressure of the slurry in the annulus is [latex]0.052\ \times 14.5\ \times 8000\ = 6032\ psi[/latex]. This means that the surface at the bottom of the well is 6032 psi greater than the surface when the fluid is not moving. When the fluid is moving, however, 550 psi of pressure is used to pump the slurry upwards. Therefore the downhole pressure is [latex]6032\ -\ 550\ =\ 5482\ psi[/latex] greater than the pump pressure. The maximum pressure allowed downhole is 6400 psi. Therefore the greatest pump pressure allowed is [latex]6400\ -\ 5482\ =\ 918\ psi[/latex]. Part B Solution: The greatest pore pressure gradient is at about 6400 ft, where the pressure is 4500 psi, or [latex]4500\ psi\ /\ 6400\ ft\ =\ 0.69\ \tfrac{psi}{ft}[/latex]. The lowest fracture pressure gradient is at about 3500 ft, where the pressure is about 2500, or [latex]2500\ psi\ /\ 3500\ ft\ =\ 0.83\ \tfrac{psi}{ft}[/latex]. It is therefore possible to pump this job as a single stage if the cement hydrostatic pressure is between 0.69 and 0.83 [latex]\tfrac{psi}{ft}[/latex]. Converting this to ppg: Minimum: [latex]0.69 \tfrac{psi}{ft} /\ 0.052\ =\ 13.26\ ppg[/latex] Maximum: [latex]0.83 \tfrac{psi}{ft} /\ 0.052\ =\ 15.9\ ppg[/latex] Neat cement or cement with a small amount of extender is acceptable for this job. Assessment Primary Cementing (adsbygoogle = window.adsbygoogle || []).push({}); 1. Which sequences can be followed for single-stage cementing? (Select all that apply.) A .Pump wash, drop bottom plug, pump cement, drop top plug, displace cement with mud CorrectB .Drop bottom plug, pump cement, pump spacer, drop top plug, displace cement with mudC .Drop bottom plug, pump spacer, pump cement, drop top plug, displace cement with mud CorrectD .Pump wash, drop bottom plug, pump spacer, pump cement, drop top plug, displace cement with mud Correct 2. Pumping excess cement slurry to ensure annular fill can cause __ if the borehole is closer to gauge than expected. A .A drop in hydrostatic pressureB .Fracture of the formation CorrectC .Zonal communication 3. When zonal isolation is particularly critical, what type of cement-filled casing packers can be utilized? A .InnerB .CirculatingC .External Correct 4. Challenges to getting a good primary cement job in the horizontal section of a Marcellus Shale well include __. (Select all that apply.) A .drill cuttings CorrectB .fractures and faults CorrectC .doglegs CorrectD .high temperaturesE .washouts CorrectF .borehole cavings Correct 5. Casing programs are an integral element of the well planning and design process. In general, casing programs reflect a _ or _ process. (Select all that apply.) A .top-downB .outside-inC .inside-out CorrectD .bottom-up Correct (adsbygoogle = window.adsbygoogle || []).push({}); 6. What is required of a well–planned and executed cement job? (Select all that apply.) A .The wellbore is drilled true to gauge. CorrectB .Recovery processes are pre-designed.C .Quality control procedures are followed. CorrectD .The cement slurry design is tested in the laboratory. CorrectE .A densified cement is used. 7. Due to smaller annular spaces, mud cake and gelled mud removal can be particularly difficult in what cementing method? A .Multiple-stageB .Single-stageC .Liner Correct 8. There are a number of challenges in cementing subsea wells, particularly those in deep water. These include: (Select all that apply.) A .The high temperatures at the seafloor and within the deeper subsurface formations and the impact on cement slurry characteristicsB .The presence of relatively shallow water-producing or gas-producing zones that must be cemented quickly and effectively CorrectC .The added hydrostatic pressure from the additional distance above the subsea assembly and the smaller degree of separation between pore pressure and fracture pressure CorrectD .The complications introduced by the extended reach or horizontal wellbores commonly employed to develop offshore reservoirs from single subsea well templates Correct 9. Identify the special challenges of cementing horizontal intervals. (Select all that apply.) A .Formation of free-water phase in cement slurry on high side of annulus CorrectB .Impact of decreased drag within the horizontal interval on hole conditionsC .Controlling the U-Tube effectD .Maintaining borehole stability during cementing CorrectE .Cleaning of the low side of the borehole of both cuttings and mud Correct 10. Due to the development of low density-high-strength cements, which type of primary cementing is least likely to be part of a well’s cementing program? A .Single-stage cementingB .Multi-stage cementing CorrectC .Liner cementing 11. Multiple-stage cementing is uncommon today due to __. A .targeting of deeper reservoirs where fracture gradients are much higherB .development of high-strength, low-density cement formulations CorrectC .improved, higher strength casing Recommended for You (adsbygoogle = window.adsbygoogle || []).push({}); Introduction to Well Cementing Chemistry and Classification of Oil well Cements Cement Additives in Drilling Cement Testing Procedures Cement Slurry Flow Properties and Mud Displacement Cementing Equipment (adsbygoogle = window.adsbygoogle || []).push({});