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This Delaware Basin case history describes a bradenhead cementing method that improves zonal isolation and top of cement (TOC). Common solutions for cementing depleted formations include stage tools, low-density slurries and reverse circulation. For this bradenhead method, cement is pumped through the wellhead valves and down the annulus to a target loss zone. Field data, lab data and the engineering model support the improvement bradenhead cementing provides across depleted formations. The depleted Brushy Canyon formation serves as an injection interval for a two-stage bradenhead cement job. This approach isolates formations below the Brushy Canyon with a conventional first stage, while achieving TOC with the second stage pumped down the annulus. Fracture gradients of the injection interval and casing shoe constrain the cement design. To achieve adequate cement placement, the design phase includes the pressure calculations required to initiate flow and injection for the bradenhead stage. Reactive spacers are utilized to prevent annulus fluid level drop in extreme cases. A benchmarked cement bond log (CBL) quantifies the results and validates this unconventional cementing method. More than 50 two-stage bradenhead cement jobs were executed with a TOC success rate of 100% in intermediate and production hole applications. CBL data obtained after cementing the intermediate casing confirms the two-stage bradenhead as a placement method. In areas constrained by casing shoe pressures, CBL data identified potential areas of shallow injection. These data resulted in a modification of the fluids pumped. Use of these re-engineered fluids reduced injection initiation pressures and improved cement bonding across salt and anhydrite formations. Cementing costs were reduced by eliminating stage tools, annular casing packers, and low-density cement slurries. Pumping the bradenhead job offline (off the rig's critical path) reduces cost further. These features support bradenhead cementing as an effective solution for wellbore sections with a potential injection zone. The regulatory requirement to place cement above depleted formations resulted in many innovative cementing methods. Stage tools, low-density slurries, and reverse circulation are attempts to avoid formation breakdown, but these methods increase cost and have limited reliability and integrity. Bradenhead cementing takes advantage of the depleted interval to aid in cement placement. Although counterintuitive, bradenhead cementing has proved to be a cost-effective solution that improves zonal isolation and eliminates integrity risks associated with stage tool failures.
This Delaware Basin case history describes a bradenhead cementing method that improves zonal isolation and top of cement (TOC). Common solutions for cementing depleted formations include stage tools, low-density slurries and reverse circulation. For this bradenhead method, cement is pumped through the wellhead valves and down the annulus to a target loss zone. Field data, lab data and the engineering model support the improvement bradenhead cementing provides across depleted formations. The depleted Brushy Canyon formation serves as an injection interval for a two-stage bradenhead cement job. This approach isolates formations below the Brushy Canyon with a conventional first stage, while achieving TOC with the second stage pumped down the annulus. Fracture gradients of the injection interval and casing shoe constrain the cement design. To achieve adequate cement placement, the design phase includes the pressure calculations required to initiate flow and injection for the bradenhead stage. Reactive spacers are utilized to prevent annulus fluid level drop in extreme cases. A benchmarked cement bond log (CBL) quantifies the results and validates this unconventional cementing method. More than 50 two-stage bradenhead cement jobs were executed with a TOC success rate of 100% in intermediate and production hole applications. CBL data obtained after cementing the intermediate casing confirms the two-stage bradenhead as a placement method. In areas constrained by casing shoe pressures, CBL data identified potential areas of shallow injection. These data resulted in a modification of the fluids pumped. Use of these re-engineered fluids reduced injection initiation pressures and improved cement bonding across salt and anhydrite formations. Cementing costs were reduced by eliminating stage tools, annular casing packers, and low-density cement slurries. Pumping the bradenhead job offline (off the rig's critical path) reduces cost further. These features support bradenhead cementing as an effective solution for wellbore sections with a potential injection zone. The regulatory requirement to place cement above depleted formations resulted in many innovative cementing methods. Stage tools, low-density slurries, and reverse circulation are attempts to avoid formation breakdown, but these methods increase cost and have limited reliability and integrity. Bradenhead cementing takes advantage of the depleted interval to aid in cement placement. Although counterintuitive, bradenhead cementing has proved to be a cost-effective solution that improves zonal isolation and eliminates integrity risks associated with stage tool failures.
Summary This Delaware Basin case history describes a bradenhead cementing method that improves zonal isolation and top of cement (TOC). Common solutions for cementing depleted formations include stage tools, low-density slurries, and reverse circulation. For this bradenhead method, cement is pumped through the wellhead valves and down the annulus to a target loss zone. Field data, laboratory data, and the engineering model support the improvement bradenhead cementing provided across depleted formations. The depleted Brushy Canyon Formation serves as an injection interval for a two-stage bradenhead cement job. This approach isolates formations below the Brushy Canyon with a conventional first stage, while achieving TOC with the second stage pumped down the annulus. Fracture gradients of the injection interval and casing shoe constrain the cement design. To achieve adequate cement placement, the design phase includes the pressure calculations required to start flow and injection for the bradenhead stage. Reactive spacers are utilized to prevent annulus fluid level drop in extreme cases. A benchmarked cement bond log (CBL) quantifies the results and validates this unconventional cementing method. More than 50 two-stage bradenhead cement jobs were executed with a TOC success rate of 100% in intermediate and production hole applications. CBL data obtained after cementing the intermediate casing confirm the two-stage bradenhead as a placement method. In areas constrained by casing shoe pressures, CBL data identified potential areas of shallow injection. These data resulted in a modification of the fluids pumped. Use of these re-engineered fluids reduced injection initiation pressures and improved cement bonding across salt and anhydrite formations. Cementing costs were reduced by eliminating stage tools, annular casing packers, and low-density cement slurries. Pumping the bradenhead job offline (off the rig’s critical path) reduces cost further. These features support bradenhead cementing as an effective solution for wellbore sections with a potential injection zone. The regulatory requirement to place cement above depleted formations resulted in many innovative cementing methods. Stage tools, low-density slurries, and reverse circulation are attempts to avoid formation breakdown, but these methods increase cost and have limited reliability and integrity. Bradenhead cementing takes advantage of the depleted interval to aid in cement placement. Although counterintuitive, bradenhead cementing has proved to be a cost-effective solution that improves zonal isolation and eliminates integrity risks associated with stage tool failures.
The global oil market remains uncertain in terms of the potential risk factors affecting the project deliverability targets. Therefore, the operators and service providers should continuously strive to enhance operational efficiency. The Tembikai field is a marginal field in shallow waters offshore Malaysia. Meeting the operational efficiency targets was paramount to develop and make the field economically viable. To achieve the aggressive targets, a fully offline cementing operation was introduced, which resulted in an average savings of 24 hours by offline cementing alone and 14% improved operational efficiency for each well. The five Tembikai Gas development wells were batch drilled using a jack-up rig. All wells consisted of 9 5/8 in. surface casings, 7 in. intermediate casings, and 3 1/2 in. cemented monobore completion tubing. Offline cementing for all three casing strings was planned. The offline cementing operation was performed after landing the casing at desired depth, then the rig is immediately skidded to the next well slot. While the casing is cemented offline, the rig drills the next well section, thus creating simultaneous operation efficiencies. After completing the surface section of each batch drilled well, the rig is positioned to the first well again to drill the intermediate section and the same process is repeated. Offline cementing eliminates wait on cement time (WOC) and enables the operator to perform other activities offline like running the gyro on the slickline to survey the inside of the previous casing, running cement bond logs etc. To perform the offline cementing, a separate high-pressure cementing line was rigged up to the platform. A custom-made offline cementing assembly was used. A special compact cement head, preloaded with cement plugs, was rigged up above the wellhead compact housing. This compact cement head is 33% shorter and lighter than conventional cement heads, which helped improve the safety aspects of this operation. Providing a dependable zonal isolation barrier is key for the success of an offline cementing operation. Tailored cement slurries for each section were designed to meet well requirements and advanced three-dimensional (3D) modeling software was used to simulate hole cleaning and cement slurry placement. All risks and mitigations for offline cementing such as shallow gas hazards, losses, gas kick etc. were covered in the cementing design of service (DOS) document. As a result of detailed planning and focused execution, 24 hours were saved per well by offline cementing alone, resulting in an average of seven days per well from drilling to completion of all wells in the campaign. The collaboration between the operator and cementing service provider for offline operations has proven to be a significant shift in operational efficiency in Malaysia, with time and cost savings achieved. These wells have achieved the lowest well cost per foot for current development wells in Malaysia.
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