Wellbore Stabilizing Technology Enhances Cementing Efforts in the North Sea

2021 ◽  
Author(s):  
Agnieszka Ilnicka ◽  
Antonio Bottiglieri ◽  
Maja Jaskiewicz ◽  
David Kulakofsky
Keyword(s):  
North Sea ◽  
Drilling Fluid ◽  
Cement Slurry ◽  
Weak Zone ◽  
Two Fluids ◽  
The North ◽  
Zonal Isolation ◽  
The North Sea ◽  
Isolation Requirements ◽  
Cement Integrity

Abstract North Sea lithologies are often complex creating a difficult environment to deliver effective zonal isolation with standard cementing practices. With ever-present weak, fractured, and unconsolidated formations, the practice of fully lifting heavier cement up the annular gap between the formation and the casing or liner often times compromises the formation and the cement integrity. Wellbore Stabilizing (WBS) technology has been shown capable of providing zonal isolation under these difficult conditions. A cementing spacer has been developed that incorporates WBS technology providing a simple way to deliver the technology in front of any cement job, without compromising the cement integrity or requiring any last-minute slurry design or redesign. By separating the placement of the WBS technology from the cement itself, the cement slurry can be designed with the sole focus being on the interval's zonal isolation requirements. On Askepott wells in the Norwegian part of the North Sea, the Nordland weak zone is encountered after drilling out the 30-inch shoe from the Oseberg Vest H template. Cement back to the seafloor is required when cementing the 20-in casing in these 26-in. holes. Prior to the introduction of the WBS technology, pressure had been observed on the D-annulus, hinting at a lack of sufficient cement circulation. With assistance from this new WBS spacer, pressure is no longer observed in the D-annulus indicating the cement is now being circulated back inside of the conductor string. The WBS spacer has also been used successfully ahead of cement across the production interval in wells where losses were typically expected, and again full returns were observed. Normally cement spacers are utilized to separate the drilling fluid from the cement as these two fluids are normally incompatible with each other and to help push the drilling fluid out of the well so the annulus may be completely filled with cement. If the drilling fluid is not successfully displaced from the annular space, the zonal isolation intended by the primary cement job is usually less than ideal. In addition to these standard functions in preparation for cementing operations, this specialized WBS spacer also can prevent loss of cement to the formation.

Application of Tracers in Oil-Based Mud for Obtaining High-Quality Fluid Composition in Lean Gas/Condensate Reservoirs

2007 ◽  
Vol 10 (01) ◽  
pp. 5-11 ◽  
Author(s):  
Fathollah Gozalpour ◽  
Ali Danesh ◽  
Adrian Christopher Todd ◽  
Bahman Tohidi
Keyword(s):  
Drilling Fluid ◽  
Gas Condensate ◽  
Fluid Composition ◽  
Drilling Process ◽  
Two Fluids ◽  
The North ◽  
Reservoir Fluid ◽  
Partially Miscible ◽  
The North Sea ◽  
Mud Filtrate

Summary Oil-based drilling fluids are used extensively in drilling activities worldwide. During the drilling process, because of overbalance pressure in the mud column, the filtrate of oil-based mud invades the formation. This hydrocarbon-based filtrate mixes with the formation hydrocarbon, which can cause major difficulties in obtaining a representative reservoir-fluid sample. Despite the recent improvements in sampling, obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Depending on the type and conditions of the reservoir, the oil-based-mud filtrate is totally or partially miscible with the formation fluid. Oil-based-mud filtrate dissolves completely in reservoir oil; therefore, the captured sample contains the true reservoir oil with added filtrate. Gas condensate (lean gas condensate in particular) is often not fully miscible with mud filtrate. In this case, the mass exchange between gas condensate and mud filtrate makes the sample unrepresentative of the reservoir fluid. In this study, the impact of sample contamination with oil-based-mud filtrate on different types of reservoir fluids, including gas condensate and volatile-oil samples, is investigated. Two simple methods are suggested to retrieve the uncontaminated composition from a contaminated sample in which mud filtrate is totally dissolved in the formation fluid (i.e., reservoir-oil samples). A tracer-based technique is also developed to determine the composition of an uncontaminated reservoir-fluid sample from a sample contaminated with oil-based-mud filtrate, particularly for those cases in which the two fluids are partially miscible. The tracers are added to the drilling fluid, with the additional cost to the drilling-mud preparation being negligible. The capability of the developed techniques has been examined against deliberately contaminated reservoir-fluid samples under controlled conditions in the laboratory. The results indicate the reliability of the proposed methods. Introduction Historically, most drilling in the North Sea has used water-based muds; however, drilling certain formations with water-based muds can be difficult, primarily because of the hole instability caused by the swelling of water-absorbing rock. Problems of this type can be greatly alleviated by using mud suspended in an oil (rather than water) base. These oil-based muds also provide better lubrication and achieve significant increases in drilling progress (Davies et al. 1984). In recent years, oil-based drilling fluid has been used extensively in drilling activities in the North Sea. During the drilling process, because of overbalance pressure in the mud column, the mud filtrate invades the reservoir formation. Using an oil-based mud in the drilling, the mud filtrate can mix with the formation fluid. This can cause major difficulties in obtaining high-quality formation-fluid samples. Depending on the type and conditions of the reservoir, the mud filtrate can be totally or partially miscible with the formation fluid. This can alter the composition and phase behavior of the reservoir fluid significantly. Hence, the measured data using the collected formation-fluid samples need to be corrected for the contamination. In this study, contamination of different types of reservoir fluids with oil-based-mud filtrate, where the two fluids are partially or totally miscible, is discussed. Practical decontamination techniques are proposed to retrieve the original fluid composition from contaminated samples.

Field Testing of a Cationic Polymer/Brine Drilling Fluid in the North Sea

1992 ◽  
Author(s):  
T.W. Beihoffer ◽  
F.B. Growcock ◽  
C.K. Deem ◽  
D.S. Dorrough ◽  
R.P. Bray ◽  
...  
Keyword(s):  
North Sea ◽  
Drilling Fluid ◽  
Field Testing ◽  
Cationic Polymer ◽  
The North ◽  
The North Sea

Aphron-based Drilling Fluid: Novel Technology for Drilling Depleted Formations in the North Sea

2003 ◽  
Author(s):  
Craig C. White ◽  
Adrian P. Chesters ◽  
Catalin D. Ivan ◽  
Sven Maikranz ◽  
Rob Nouris
Keyword(s):  
North Sea ◽  
Drilling Fluid ◽  
The North ◽  
Novel Technology ◽  
The North Sea

Automated Drilling-Fluids-Measurement Technique Improves Fluid Control, Quality

2021 ◽  
Vol 73 (11) ◽  
pp. 53-54
Author(s):  
Chris Carpenter
Keyword(s):  
Ambient Temperature ◽  
North Sea ◽  
Drilling Fluid ◽  
Pressure Sensors ◽  
Drilling Fluids ◽  
Sampling Point ◽  
Electrical Stability ◽  
The North ◽  
Fluid Properties ◽  
The North Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204041, “Automatic Drilling-Fluids Monitoring,” by Knut Taugbøl, SPE, Equinor, and Bengt Sola and Matthew Forshaw, SPE, Baker Hughes, et al., prepared for the 2021 SPE/IADC International Drilling Conference and Exhibition, originally scheduled to be held in Stavanger, 9–11 March. The paper has not been peer reviewed. The complete paper presents new units for automatic drilling-fluids measurements with emphasis on offshore drilling applications. The surveillance of fluid properties and the use of data in an onshore operations center is discussed. The authors present experiences from use of these data in enabling real-time hydraulic measurements and models for automatic drilling control and explain how these advances can improve safety in drilling operations and drilling efficiency. Introduction An operator has worked with different suppliers for several years to find and develop technology for automatic measurements of drilling-fluid properties. In the described study, methods for measuring parameters such as viscosity, fluid loss control, pH, electrical stability, particle-size distribution, and cuttings morphology and mineralogy were all fitted into a flow loop in an onshore test center. These tests, however, were all performed with prototype equipment. Since then, work has continued to optimize equipment for offshore installations, made for operating in harsh environments and requiring limited maintenance to provide continuous and reliable data quality. The fluid-measuring technique presented in this paper is based on rheology measurement through a pipe rheometer and density measurements through a Coriolis meter. This rheometer measures at ambient temperature. Dual DP is the terminology that refers to pressure measurements between two differential pressure sensors. The dual-DP pipe rheometer is set up with high-accuracy pressure transducers to measure pressure loss inside the straight section of the pipe rheometer. By varying the flow rate through pipes of different dimensions, a rheology profile at varying shear rates can be calculated. Field Implementation Installation of a unit begins with a rig survey conducted in concert with the drilling contractor to find the best location and sampling point. Fluid normally is taken from the charge manifold for the mud pumps, ensuring measurement of the fluid going into the well. The first installation in the North Sea of an automatic fluid-monitoring (AFM) unit was in 2017. This unit is still operational, sending data to an onshore support center. Fig. 1 shows such a unit installed offshore. The AFM unit has only one movable part, the monopump supplying drilling fluid through the unit. Once the dual-DP rheometer was factory-acceptance-tested in the yard, it was sent offshore to be commissioned and verified on a fixed installation in the North Sea. The related data presented in the complete paper were acquired in the field while drilling the 355-m, 8½-in. section with 1.35-SG low-equivalent-circulating-density oil-based drilling fluid, with drilling conducted at approximately 4000 m measured depth. The mud engineer onboard was requested to perform rheology checks on a viscometer at equal ambient temperature to the AFM so that the results could be compared; the AFM also measures rheology at ambient temperature.

Successful Off Bottom Cementation of a Highly Deviated 4 ½ in Production Liner in UAE

2021 ◽  
Author(s):  
Ahmedagha Hamidzada ◽  
Ahmed Rashed Alaleeli ◽  
Azza El Hassan ◽  
Fatima Bin Tarsh ◽  
Islam Abdelkarim
Keyword(s):  
Drilling Fluid ◽  
High Viscosity ◽  
High Yield ◽  
Cement Slurry ◽  
Engineering Approach ◽  
Main Challenge ◽  
Narrow Side ◽  
Fluid Properties ◽  
Zonal Isolation ◽  
Cement Integrity

Abstract Cementing a highly deviated production liner is associated with cement placement challenge that can compromise zonal isolation. A major operator in UAE, was facing a challenge to cement 4 ½ in slim production liner set at + 5000 ft off-bottom. The corresponding 6 in. section was drilled with a relatively high mud weight in the range of 12 to 13 PPG. One of the main challenge was the risk of solids settling on the low side of the wellbore, making mud displacement difficult to achieve while cementing. Additionally, cementing off-bottom without an ECP in a highly deviated wellbore with multiple exposed production zones, further increased cement placement complexity. A holistic engineering approach was integrated to ensure successful zonal isolation. Wellbore parameters and fluid properties were critically evaluated. To overcome off-bottom cementing and prevent slurry fallback risks, a weighted high viscosity pill with high yield point was placed as a temporary basement to support the cement column and isolate the reservoir during 4 ½ in liner job. After placement of the pill, the wellbore was observed for flow checks to ensure stable downhole conditions prior to displacing the drilling fluid across the liner interval to brine within the same density. A centralization program was implemented to achieve more than 70% stand-off which required a minimum centralization pattern of two rigid centralizers per joint which helped minimize the presence of mud channels on the narrow side. Effective mud removal was ensured through implementation of a spacer train in front of the cement. The first spacer was pumped with same mud density to reduce ECD followed by another advanced low invasion loss circulation spacer to mitigate losses as well as provide a sustained downhole rheology. A resilient, expandable and gas tight cement slurry, was selected to target long-term zonal isolation. Multiple hydraulic simulations were performed to optimize ECDs and ensure safe margins during placement A CFD (computational fluid dynamics) model was utilized to simulate hydraulics, expected mud removal and fluids inter-mixing especially during liner rotation. In addition, the model simulated high-calculated torques based on flow restrictions through liner hanger assembly. Lack of mechanical liner movement was compensated by additional pre-job circulation to fully condition the wellbore. The job was executed with no losses during cementing, and spacer and cement returns were received on the surface during reverse out. Utilizing the best engineering approach, practices, and techniques from this job is implemented in the future wells as the production of the well is directly affected by the cement quality. Post job cement integrity evaluation via a cement bond log confirmed excellent bonding of cement to the liner and reservoirs across the entire open-hole interval.

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