Pushing the Frontier in Deepwater HP/HT Drilling by Application of Wellbore Strengthening—A Practical Approach

2021 ◽  
Author(s):  
Sultan Alimuddin ◽  
Catalin Aldea ◽  
James Hunter Manson ◽  
Kantaphon Temaismithi
Keyword(s):  
High Pressure ◽  
Drilling Fluid ◽  
Treatment Plan ◽  
Strengthening Mechanism ◽  
Management Program ◽  
Case Scenario ◽  
Well Design ◽  
High Pressure High Temperature ◽  
Fluid Formation ◽  
Wellbore Strengthening

Abstract This paper presents a comprehensive laboratory and field study, discussing the development, formulation, and application of a wellbore strengthening mechanism, for strengthening weak formations while drilling in a deepwater high-pressure/high-temperature (HP/HT) well environment. The use of this technology has potential to eliminate nonproductive time (NPT) related to downhole losses, along with extending the drillability of sections and eliminating additional casing strings, during exploratory drilling. During the planning phase of a sequence of deepwater and HP/HT exploration wells, the potential high-pressure case scenario drove the planned and contingency well casing designs. This led to an extensive casing program with a 16-in. sub mudline hanger casing string added to the base design, as well as the normal 36-in. conductor, 20-in. surface casing, 13 ⅜-in. intermediate casing, and 9 ⅝-in. casing, which would enable reaching total depth (TD) within a planned 8 ½-in. hole. The realistic offset well driven by the high-pressure case also required two further contingency liner strings (11 ¾ in. and 7 in.), to be included in the well design. A key enabler for the sequence of wells was that the semisubmersible rig was upgraded to include a managed pressure drilling (MPD) below tension ring (BTR) arrangement. This was enhanced by the MPD well control system and associated risk assessment, allowing working to reduced acceptable kick tolerance limits. In addition to the outlined base and contingency plans, wellbore strengthening was also to be available, as an additional contingency application, to reach TD objectives. Thus, extensive laboratory tests were performed for wellbore strengthening design, using proprietary software, along with past established practices. Subsequent to laboratory testing and the optimal formulation, a detailed wellbore strengthening program was prepared and included in the drilling program, for potential use at any point while drilling ahead. On one well, after cementing of 13 ⅜-in. casing and performing a leakoff test (LOT), it was found that the value was insufficient for drilling through the entire planned section. A contingency 11 ¾-in. liner was being enabled before it was decided to pump the wellbore strengthening pill and strengthen the casing shoe. The pill application gave sufficient increased formation strength, leading to the well section being successfully drilled and cased with no losses, even though the high-pressure well scenario was actually encountered. This solution eliminated the time and cost implication and considerable operational challenges of the 11 ¾-in. contingency liner. This paper presents the study of conceptualizing the wellbore strengthening mechanism and implementing this customized solution in the field. A detailed analysis is also done to identify the optimal products, compatibility with drilling fluid, formation and existing chemical permit, and cost-effectiveness and savings using wellbore strengthening practice. The paper also discusses the comprehensive pit management program and required treatment plan while drilling.

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.

Effect on Fracture Pressure by Adding Iron-Based and Calcium-Based Nanoparticles to a Nonaqueous Drilling Fluid for Permeable Formations

2016 ◽  
Vol 138 (3) ◽  
Author(s):  
Oscar Contreras ◽  
Mortadha Alsaba ◽  
Geir Hareland ◽  
Maen Husein ◽  
Runar Nygaard
Keyword(s):  
Drilling Fluid ◽  
Filter Press ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Fracture Pressure ◽  
High Pressure High Temperature ◽  
Iron Based ◽  
Wellbore Strengthening ◽  
Fracturing Experiments

This paper presents a comprehensive experimental evaluation to investigate the effects of adding iron-based and calcium-based nanoparticles (NPs) to nonaqueous drilling fluids (NAFs) as a fluid loss additive and for wellbore strengthening applications in permeable formations. API standard high-pressure-high-temperature (HPHT) filter press in conjunction with ceramic disks is used to quantify fluid loss reduction. Hydraulic fracturing experiments are carried out to measure fracturing and re-opening pressures. A significant enhancement in both filtration and strengthening was achieved by means of in situ prepared NPs. Our results demonstrate that filtration reduction is essential for successful wellbore strengthening; however, excessive reduction could affect the strengthening negatively.

South Texas Hybrid Monobore High Pressure, High Temperature Well Design

2003 ◽  
Author(s):  
Rich Billa ◽  
Doug Gordon ◽  
Ed Watterson ◽  
Jose Mota
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
South Texas ◽  
Well Design ◽  
High Pressure High Temperature
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