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Elhassan, Azza (ADNOC Offshore) | Hamidzada, Ahmedagha Eldaniz (ADNOC Offshore) | Takahiro, Toki (ADNOC Offshore) | Motohiro, Toma (ADNOC Offshore) | Orfali, Mohd Waheed (Schlumberger) | Phyoe, Thein Zaw (Schlumberger) | Salazar, Jose (Schlumberger) | Alaleeli, Ahmed Rashed (ADNOC Offshore)
Abstract Good cementing practices are required to achieve effective zonal isolation and provide long-term well integrity for uninterrupted safe production and subsequent abandonment. Zonal isolation can be attained by paying close attention to optimizing the drilling parameters, hole cleaning, fluid design, cement placement, and monitoring. In challenging extended reach wells in the UAE, different methods were employed to deliver progressive improvement in zonal isolation. Cementing the intermediate and production sections in the UAE field is challenging because of the highly deviated, long, open holes; use of nonaqueous fluids (NAFs); and the persistent problem of lost circulation. Compounding the problem are the multiple potential reservoirs; the pressure testing of the casing at high pressures after cement is set; and the change in downhole pressures and temperatures during production phases, which results in additional stresses. Hence, the mechanical properties for cement systems must be customized to withstand the downhole stresses. The requirement of spacer fluids with nonaqueous compatible properties adds complexity. Lessons learned from prior operations were applied sequentially to produce fit-for-purpose solutions in the UAE field. Standard cement practices were taken as a starting point, and subsequent changes were introduced to overcome specific challenges. These challenges included deeper 12 ¼-in. sections, which made it difficult to manage equivalent circulating densities (ECDs), and a stricter requirement of zonal isolation across sublayers in addition to required top of cement at surface. To satisfy these requirements, several measures were taken gradually: applying engineered trimodal blend systems to remain under ECD limits; pumping a lower-viscosity fluid ahead of the spacer; using NAF-compatible spacers for effective mud removal; employing flexible cement systems to withstand downhole stresses; and modeling the cement job with an advanced cement placement software to simulate displacement rates, bottomhole circulating temperatures, centralizer placement, mud removal and comply with a zero discharge policy that restricts the extra slurry volume to reach surface. To enhance conventional chemistry-based mud cleaning, an engineered scrubbing additive was included in the spacers with a microemulsion-based surfactant. The results of cement jobs were analyzed by playback in advanced evaluation software to verify the efficiency of the applied solutions. This continuous improvement response to changes in well design has resulted in a significant positive change in cement bond logs; a flexural attenuation measurement tool has been used to evaluate the lightweight slurry quality behind the casing, which has helped in enhancing the confidence level in well integrity in these challenging wells. The results highlight the benefit of developing engineering solutions that can be adapted to respond to radical changes in conditions or requirements.
Abstract Monobore cementation is defined as where a single production tubing size runs from the pay zone all the way to surface and is cemented in place. This type of well design greatly reduce rig time and cost. The challenge however is to achieve a good cement in the annulus as a well barrier and to have a clean internal tubing after the cementing job to allow for successful production of the well. To achieve a clean internal tubing, a distinct bottom and top plugs were used as a means of mechanical separation. For fluids design, mud had to be thinned down prior to the cementing job and, a designed fiber based spacer system was used to physically scrub any mud-film sticking on the tubing walls. The centralizers and cement system were designed to allow for efficient displacement of mud and hence providing good overall placement and top of cement in the tubing-casing annulus. The cement in the annulus will be verified by pressure testing the annulus to 500 psi higher than previous shoe leak-off. This approach was implemented for the campaign of six wells, all designed with 5-1/2in monobore tubing. The bottomhole static temperature (BHST) of the well ranges from 300 to 350°F. The cementing system also had to be designed to cater to the challenge of this field, having CO2 as high as 60%, high temperatures, and a long open hole section that requires isolation and cement to set within a required timeframe. The cementing jobs were validated by no losses or gains during the job, floats holding at the end of the cementing job, differential pressure of cement prior to bumping the plug, density and pump rates executed as planned, accepted pressure test criteria of the annulus, output validation of cement contamination in pipe and annulus based on fluids and final well information. To further validate this system, the cement bond log was also run as part of the evaluation process and the cement log showed that zonal isolation was achieved. After the perforations, the perforation tool was pulled out to surface and the tool looked very clean with no signs of contaminated mud or cement around the tool. We demonstrate how this unique cementing approach can be a solution for the challenges of monobore cementing and one of the biggest problems of monobore cementing in the industry.
Zaman, Mohammad (Santos Ltd) | Shaban, Alex (Santos Ltd) | Iyer, Venkat (Halliburton Australia Pty Ltd) | Wuthayavanich, Ekkalak (Halliburton Australia Pty Ltd) | Saunders, Troy (Halliburton Australia Pty Ltd)
Complete to intermittent dynamic losses during drilling operations in the Early Permian reservoirs of the Bowen Basin are common because of depleted zones, particularly in the Bandana Coal Measures. The losses encountered while attempting to drill to total depth (TD) result in notable setbacks in time, remediation costs, and zonal isolation integrity. Operators have access to a large portfolio of loss circulation (LC) treatments depending on the loss type, rate, and nature of losses. This paper presents a low-solids, highly thixotropic (LSHT) cement system that can help cure losses without incurring costly nonproductive time (NPT).
During the recent Springwater campaign, which consisted of 12 wells targeting the Cattle Creek Coal Measures, three of the wells experienced significant to total losses. A number of conventional lost circulation materials (LCMs), including particulate materials, reticulated foams, and fibers, were unsuccessful in curing the losses. As an alternative to a conventional LC cement plug, an LSHT cement system was deployed.
The low-solids content and avoidance of any traditional LCMsenable the LSHT system to be pumped through the bottomhole assembly (BHA), which allows for continued drilling. The LSHT cement system is shear-rate dependent, yielding to thin rheologies on application of shear to easily penetrate into the loss zone. When shear is reduced, the slurry gels rapidly to arrest the rate of flow. Additionally, the quick early compressive strength development at shallow depths allows operations to continue without incurring significant loss of operating hours. The solutions provided were pumped through open-ended pipe in one case and through the BHA with a drilling bit in another; both performed in the same manner without hampering equipment capability.
Successful application of the LSHT cement technology helps minimize time lost using conventional cement plugs because the LSHT cement can be pumped through the BHA, saving time associated with tripping in and out of the hole to change the BHA. Additionally, the system's early compressive strength development yields time savings, along with savings in otherwise lost fluids, and achieves drilling efficiencies to help manage drilling operations costs.
Pump and pull cementing method is introduced to overcome soft cement plugs due to the swabbing effect and contamination in an oil-based mud environment. The method aims to address quality concerns in challenging well profiles where conventional cementing techniques are deemed to fail, which potentially lead to additional cost for remedial cementing work and non-productive rig time.
The method is utilized to tackle a re-occurring issue of tagging soft cement plugs that are used for several applications, including plugging and abandonment and sidetracking operations, in deep highly deviated or horizontal wells. In such profiles, fluids and cement don't balance themselves as gravity is not the predominant factor. Subsequently, the cement plug cannot be balanced, and contamination takes place resulting in its failure. The method targets minimizing this by reducing the effect of pulling out of the plug by keeping the drill pipe stinger inside the cement slurry and replacing the volume created while pulling out of the hole by pumping cement until completing the placement of the plug.
The technique is time sensitive since most of the cement slurry remains in drillpipe while preforming the job. For that reason, intensive planning is required to ensure successful implementation. One factor that impact the quality of the job is the abundance of actual downhole data, including caliper and temperature logs. Based on that, cement slurry design can be adjusted to account for temperature effect as well as adjusting volume calculations. Also, lab and computer simulations play a significant role in determining several parameters such as spacer formulation, mud removal efficiency, ultimate compressive strength chart, and additives concentrations, especially retarders. In terms of field preparedness, specific equipment and competencies are required for such critical jobs. The method was deployed successfully in several jobs, resulting in excellent cement quality. At the top of that, the method was used to optimize operations by pumping a single long cement plug instead of several balanced cement plugs. This has directly resulted in saving several rig days while delivering satisfactory cement hardness. A couple of case studies are introduced to showcase the effectiveness of the method in challenging applications.
Pump and pull technique proved that it resolves the challenge of placing cement plugs in highly deviated and horizontal wells. It earns more importance as wells are growing in complexity. Recently, the technique was used to successfully place significantly longer cement plugs, achieving an outstanding level of operational efficiency by saving rig days and resulting in cost optimization of cementing operations by reducing the number of required plugs to be pumped.
Pernites, Roderick (BJ Services) | Brady, Jason (BJ Services) | Padilla, Felipe (BJ Services) | Clark, Jordan (BJ Services) | McNeilly, Caitlin (BJ Services) | Iqbal, Waqas (BJ Services) | Lacorte, Juan (BJ Services) | Gonzalez, Eduardo (BJ Services) | Embrey, Mark (BJ Services)
Abstract Delivering a competent cement seal to provide wellbore zonal isolation for maximizing production is highly dependent on mud removal, which remains the perennial challenge. Non-aqueous mud is preferred during drilling to avoid formation swelling and for HTHP wells, but it is highly incompatible with aqueous-based cement fluid. More challenging, non-aqueous mud is customarily recycled and reused in multiple wells, contaminating it heavily and making it difficult to clean by many conventional spacers. This paper presents a full-scale laboratory development to a successful field application of an unconventional spacer with a novel micromaterial that enhances mud removal and provides exceptional fluid stability (flat viscosity), important for long horizontals. Due to its differentiating chemistry combined with uniquely engineered physical properties (minimally abrasive yet non-damaging to equipment), the new micromaterial allows more efficient scouring of strongly adhered mud from casing/formation surfaces, which many traditional spacers have difficulty removing efficiently. To demonstrate efficient mud removal, numerous standard rotor cleaning tests were performed with different muds from across North America. Free water and HPHT dynamic settling tests were used to evaluate thermal stability of the spacer. Wettability and API compatibility tests were completed. XRD and SEM analyses were used to characterize and understand the unique properties of the novel micromaterials that contribute to enhanced mud cleaning. First field application was successfully completed in the Permian Basin. Field trial has proven the new spacer (11.3 ppg design with 134 bbl total volume) to be highly stable when pumping down (5 bbl/min) into a wellbore of over 20,000 ft (6096 m) depth with ~12,000 ft (~3658 m) horizontal and 139°F (59°C) BHCT. Most of the oil-based mud used during drilling was recovered.
Abstract A lightweight cement solution was successfully applied in deepwater wells at depths greater than 1000 m and in production liners terminating in depleted reservoirs. These wells were drilled off the east coast of India. The fracture gradient prognosis for the depleted zones ranged from 11.0 to 11.28 lbm/gal. The measured depth (MD) of these wells was more than 4500 m (MDRT). Mud weights ranged from 10.9 to 11 lbm/gal in the well while drilling the zone. The length of the liner normally ranged from 1400 to 2300 m. The cement slurry was finalized after conducting numerous tests in the laboratory. A lead and tail combination was used for the job to maintain the required equivalent circulating density (ECD). In openhole completions, the casing or liner before the gravel pack should be landed in sand to establish having reached the reservoir top and to help ensure that no shale is present. Challenges for a successful liner job in these wells include landing in a depleted reservoir, which would enable a very low margin between the mud weight and fracture gradient. This margin is further reduced by the minimum horizontal stress mud weight requirement to help ensure that no hole collapse occurs while drilling and before cementing begins. In addition to the depleted zone, to maximize reservoir tapping, the well profiles are highly deviated, often reaching a well deviation of 80+ degrees, resulting in a high ECD during cementing. A long section of the cement column can create problems of cement channeling past the mud and mixing in the annulus. The correct prediction of pore pressure and fracture pressure for different sections is very important. Accurate knowledge of these values is recommended for a correct job design. Some of the lessons learned during the process to help ensure good zonal isolation include the following: An 11-lbm/gal lightweight lead slurry was formulated, keeping ECD and fluid rheology vs. strength development in mind. Solids loading was controlled to help ensure low friction factors (considering rheology) and to achieve a final compressive strength of 2,000 psi because it was a production casing. The length of the tail slurry column was maintained to a minimum to create minimal effect on the ECD, even though the hydrostatic pressure developed was marginal in a highly deviated section. A low-rheology/low-density synthetic oil-based mud (SOBM) (10 lbm/gal) was pumped ahead to reduce the ECD and to maintain the equivalent static density (ESD) above the pore pressure. In addition, the displacement rate was staggered to help maintain the ECDs. A high-viscosity pill was spotted at the 12 1/4-in. section total depth (TD) before the final pullout to act as a base for the cement slurry. This paper highlights the concerns and best practices developed when cementing production liners across depleted formations in deepwater wells.
Abstract The efficiency of the well construction process is highly dependent upon completion of the cementing phase. Drilling ahead is dependent on when the cement will build sufficient strength to support the existing casing. This paper presents a novel lightweight cementing technology through application of advanced chemistry that shows high potential for faster completion of the cementing phase, decreasing the waiting time for the cement to set, thereby allowing continued drilling operations. A unique lightweight density superior performing cement was successfully developed for high early compressive strength development that does not utilize traditional methods and materials for enhancing cement strengths like glass beads, cenospheres, silica fumes, fly ash, modified and/or natural clays.
Abstract Insufficient wellbore cleaning prior the cementing job is considered to be the biggest single factor leading to poor zonal isolation results. A mud-spacer-cement program with suitable fluid needs to be carefully engineered for the given wellbore conditions to improve cementing quality. We discuss optimum spacer design features which are critical for the successful cementation of deep deviated HPHT wells containing heavy oil based muds and review a simulated scenario. Advanced lab test methodologies beyond industry standards are utilized to model more accurately the given complex downhole conditions. A simulated >20,000 ft highly deviated wellbore was characterized by HPHT bottomhole conditions and the rheological performance of the cement spacer was critical to job success. The well needed a stable cement spacer that would not settle-out on the low side of the >14,000 ft horizontal section, which would potentially put the well at risk. The 16.17 ppg mud required an even higher-density spacer system to clean it effectively. But conventional high-density spacer systems only compound the settling challenge and the well's anticipated bottomhole temperature of 350°F was expected to compromise any additives that might stabilize the fluid systems. Therefore a lab study about spacer stability was performed using a HPHT rheometer and the dynamic settling test – an industry standard which was actually established for cement slurries but not for spacer fluids. We found that a conventional spacer failed at 350°F by showing a rapid decline in rheology to almost zero viscosity and severe settling. To overcome the settling issue, provide stability, and maintain a sufficiently high rheology profile at given 350°F, we re-designed the spacer by using a modified biopolymer which shows a delayed hydration and viscosification over time successfully counteracting the destructive thermal effects. The mud-spacer-cement fluid train was eventually optimized showing good fluid compatibility and maintaining within the narrow, 1.6 ppg margin that separated the pore pressure from the fracture gradient. The cementing job was designed using an advanced fluid displacement software, which predicted high mud removal efficiency under these challenging conditions. In order to enable proper mud displacement, the Friction Hierarchy—a key design factor that is often difficult to achieve under the extreme HPHT well conditions—was achieved with the new spacer concept.
Currently available commercial HT/HP devices include the Model 7200 Cement Hydration Analyzer by Chandler Engineering (2015, 2017), the Fluid Gas Migration Analyzer #120-57 by OFI Testing Equipment (2014), the Model 300 Gas Migration Apparatus by Cement Test Equipment (2014), the Fluid Migration Analyzer by Sanjel Corporation (2014), and the Fluid/Gas Migration Analyzer TG-7150 by Shenyang Taige Oil Equipment (2017). HT/HP devices are typically referred to as CHAs. Although the commercial CHAs seem different from one another, the philosophy and design are basically the same as the modified API fluid-loss device developed by Cheung and Beirute (1985). All available CHAs attempt to replicate the in-situ HT/HP curing history by controlling the applied pressure and temperature. The comparison of specifications between different commercial CHAs is shown in Table 2. In addition to measuring the cement susceptibility to gas migration, Model 7200 is advertised to be capable of measuring shrinkage during curing, gas permeability of the cement, and the degree of hydration (Chandler Engineering 2014). However, little information regarding the degree of hydration is available in the instruction manual for Model 7200 (Chandler Engineering 2015). A review of the design indicates that Model 7200 can determine the hydration stage using temperature increases and decreases, but is not capable of analyzing important details of cement hydration.
Abstract Differential Valves are used in multistage cementing tools to ensure having adequate cement placement and enhanced wellbore isolation. Multistage tools are recommended to use if the formation is unable to support the hydrostatic pressure of the cement column. In cases of lose circulation, multistage tools are used at designated depth to help placing cement all the way to surface. There are two types of multistage tools: conventional ones that can withstand low-pressure rating and more recently developed high-pressure rating tools. The low-pressure rating tool is used to support cement placement and is not considered as mechanical barrier against high-pressure formations. The high-pressure tools were developed based on additional requirements to improve wellbore isolation in high-pressure gas wells. The objective of this paper is to: Highlight the importance of multistage cementing tools and to de-risk their use Provide best practices to overcome common multistage tool issues Potential malfunctions can be due to either mechanical components malfunction or improper operational practices. These can be further divided into 4 categories, which are: packer issues, opening/closing DV ports, and drilling practices such as encountering losses while cementing and finally improper running operational procedures. This paper includes intensive review of actual runs including frequency of multistage tool issues based on casing size. Different mitigation plans are recommended for each potential issue and optimum drilling practices to overcome them. In addition, high-pressure multiage tools performance will be highlighted in improving wellbore isolation since their initial deployment 3 years ago.