Prevention of Barite Sagging for Invert Emulsion Drilling Fluid While Drilling High-Pressure High-Temperature Wells

2020 ◽  
Author(s):  
Salem Basfar ◽  
Salaheldin Elkatatny ◽  
Abdulaziz Al-Majed ◽  
Dhafer Al Sheri
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Drilling Fluid ◽  
High Pressure High Temperature ◽  
Invert Emulsion

scholarly journals Enhancing the Stability of Invert Emulsion Drilling Fluid for Drilling in High-Pressure High-Temperature Conditions

Energies ◽  
2018 ◽  
Vol 11 (9) ◽  
pp. 2393 ◽  
Author(s):  
Salaheldin Elkatatny
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Rheological Properties ◽  
Drilling Fluid ◽  
Electrical Stability ◽  
Dynamic Conditions ◽  
High Pressure High Temperature ◽  
Invert Emulsion ◽  
The Stability ◽  
Filtration Properties

Drilling in high-pressure high-temperature (HPHT) conditions is a challenging task. The drilling fluid should be designed to provide high density and stable rheological properties. Barite is the most common weighting material used to adjust the required fluid density. Barite settling, or sag, is a common issue in drilling HPHT wells. Barite sagging may cause many problems such as density variations, well-control problems, stuck pipe, downhole drilling fluid losses, or induced wellbore instability. This study assesses the effect of using a new copolymer (based on styrene and acrylic monomers) on the rheological properties and the stability of an invert emulsion drilling fluid, which can be used to drill HPHT wells. The main goal is to prevent the barite sagging issue, which is common in drilling HPHT wells. A sag test was performed under static (vertical and 45° incline) and dynamic conditions in order to evaluate the copolymer’s ability to enhance the suspension properties of the drilling fluid. In addition, the effect of this copolymer on the filtration properties was performed. The obtained results showed that adding the new copolymer with 1 lb/bbl concentration has no effect on the density and electrical stability. The sag issue was eliminated by adding 1 lb/bbl of the copolymer to the invert emulsion drilling fluid at a temperature >300 °F under static and dynamic conditions. Adding the copolymer enhanced the storage modulus by 290% and the gel strength by 50%, which demonstrated the power of the new copolymer to prevent the settling of the barite particles at a higher temperature. The 1 lb/bbl copolymer’s concentration reduced the filter cake thickness by 40% at 400 °F, which indicates the prevention of barite settling at high temperature.

Prediction of High-Pressure/High-Temperature Rheological Properties of Drilling Fluids from the Viscosity Data Measured on a Coaxial Cylinder Viscometer

SPE Journal ◽  
2021 ◽  
pp. 1-22
Author(s):  
Sidharth Gautam ◽  
Chandan Guria ◽  
Laldeep Gope
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Shear Viscosity ◽  
Drilling Fluid ◽  
Viscosity Model ◽  
Drilling Fluids ◽  
Viscosity Data ◽  
Monitoring And Control ◽  
High Pressure High Temperature ◽  
Proposed Model

Summary Determining the rheology of drilling fluid under subsurface conditions—that is, pressure > 103.4 MPa (15,000 psi) and temperature > 450 K (350°F)—is very important for safe and trouble-free drilling operations of high-pressure/high-temperature (HP/HT) wells. As the severity of HP/HT wells increases, it is challenging to measure downhole rheology accurately. In the absence of rheology measurement tools under HP/HT conditions, it is essential to develop an accurate rheological model under extreme conditions. In this study, temperature- and pressure-dependence rheology of drilling fluids [i.e., shear viscosity, apparent viscosity (AV), and plastic viscosity (PV)] are predicted at HP/HT conditions using the fundamental momentum transport mechanism (i.e., kinetic theory) of liquids. Drilling fluid properties (e.g., density, thermal decomposition temperature, and isothermal compressibility), and Fann® 35 Viscometer (Fann Instrument Corporation, Houston, USA) readings at surface conditions, are the only input parameters for the proposed HP/HT shear viscosity model. The proposed model has been tested using 26 different types of HP/HT drilling fluids, including water, formate, oil, and synthetic oil as base fluids. The detailed error and the sensitivity analysis have been performed to demonstrate the accuracy of the proposed model and yield comparative results. The proposed model is quite simple and may be applied to accurately predict the rheology of numerous drilling fluids. In the absence of subsurface rheology under HP/HT conditions, the proposed viscosity model may be used as a reliable soft-sensor tool for the online monitoring and control of rheology under downhole conditions while drilling HP/HT wells.

Investigation of magnetite-based invert emulsion mud at high pressure high temperature

2021 ◽  
Vol 14 (18) ◽  
Author(s):  
Wesam Almutawa ◽  
Ashraf Ahmed ◽  
Salem Basfar ◽  
Salaheldin Elkatatny ◽  
Saleh Haidary ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
High Pressure High Temperature ◽  
Invert Emulsion

Innovative Drilling Fluid Technology Conquered Tough Geomechanics Offshore Mexico

2021 ◽  
Author(s):  
Ricardo Reyna ◽  
Viridiana Parra ◽  
Daniel Volbre ◽  
Raul Ballinas ◽  
Reinaldo Maldonado ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Best Practices ◽  
Drilling Fluid ◽  
Cost Savings ◽  
Lessons Learned ◽  
New Production ◽  
Wellbore Instability ◽  
High Pressure High Temperature ◽  
Intermediate Section

Abstract The reservoir field highlighted in this paper is located Offshore Mexico in the southeast part of Campeche Bay and hidden below a troublesome, unstable formation that must be transacted before reaching the new production zone. During the exploration phase, this section experienced severe lost circulation and unstable conditions before reaching the final depth. Based on lessons learned, the team worked to develop a best- practices approach using geomechanics analysis and a novel fluid technology which enabled the operator to safely drill through this problematic intermediate section under high-pressure, high-temperature (HPHT) conditions. The methodology started with identifying the geomechanics challenges, implementing operational best practices, and finally, use of an innovative, low-invasion fluid technology, which creates a thin and impermeable shield at the wellbore wall, effectively sealing the fractures and preventing fracture propagation in the highly unstable formation of interspersed carbonates, shales, and sandstones. The strong mechanical properties of the thin, but firm, barrier created at the wellbore wall minimized the destabilizing effect of fluid invasion. Synergy from the geomechanical team, best practices for the operation, and innovative drilling fluid technology solved the wellbore instability drilling challenge encountered in the exploration well. In offset wells, losses of more than 2,200 m3 of drilling fluid, stuck pipe, and major NPT were observed. By incorporating the shielding technology, wellbore instability was improved in the intermediate section. In addition, the fluid technology was easily pumped through the bottomhole assembly (BHA) to seal formation fractures between 2,000 and 3,000 μm in size. This well, utilizing the barrier technology to mitigate the wellbore instability and drill within a narrow fracture gradient operating window, was the first in the area to have zero loss of drilling fluid as compared to the typical 5 to 10-m3/hr circulation losses experienced during exploration drilling in the intermediate section characterized by interbedded layers of carbonates, shales, and sandstone under high-pressure, high-temperature (HPHT) conditions. The coordination between the teams using best practices was critical to meeting the challenge of the intermediate geomechanically weak formation. This case history in offshore Mexico will demonstrate both the importance of teamwork and the utilization of a proven technology that improves wellbore instability, minimizes NPT, mitigates pipe tripping issues and avoids huge volumes of drilling fluid lost into the geomechanically weak formation. This barrier technology can be applied globally to troublesome formations - such as interbedded carbonates, shales, and sandstones - to improve operations and provide cost savings for the operator.

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