Stability Enhancing of Water-Based Drilling Fluid at High Pressure High Temperature (original) (raw)
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Journal of Petroleum Exploration and Production Technology, 2020
Weighting agents are mixed with the drilling mud to provide the high density required to control high-pressure high-temperature (HPHT) wells throughout the drilling operation. Solids sag occurs when the weighting agent separates from the liquid phase and settles down, causing variations in the drilling fluid density. This study evaluates barite-manganese tetroxide (Micromax) mixture to eliminate solids sag issue encountered with weighted invert emulsion drilling fluids at HPHT conditions. Micromax additive was added to barite-weighted fluids in different concentrations, 0, 15, and 30 wt% of the total weighting agent. Static and dynamic sag tests were used to evaluate the sag tendency of the new formulation under static and dynamic conditions. The performance of the new formulation was evaluated by measuring the electrical stability, density, rheological, viscoelastic, and filtration properties of the drilling fluid. The obtained results showed that Micromax additive improves drilling fluid stability by reducing the sag tendency. Adding only 30 wt% of Micromax additive eliminated barite sag issue in both dynamic and static conditions at 350 °F. 30 wt% Micromax increased the base fluid density by 5.4% and the yield point by 115% and maintained the gel strength value at 12 lb/100 ft 2 , while it reduced the plastic viscosity by 30%. The addition of Micromax additive improved the viscoelastic properties of the drilling fluid by maintaining a higher storage modulus to the loss modulus ratio when compared with the barite sample (in the range 4-4.5). Furthermore, 30 wt% Micromax improved the filtration performance by reducing the filtrate volume, filter cake weight, and filter cake thickness by 50%.
ACS Omega
Weighting agents such as barite, micromax, ilmenite, and hematite are commonly added to drilling fluids to produce high-density fluids that could be used to drill deep oil and gas wells. Increasing the drilling fluid density leads to highly conspicuous fluctuation in the drilling fluid characteristics. In this study, the variation in the drilling fluid's rheological and filtration properties induced by adding different weighting agents was evaluated. For this purpose, several water-based drilling fluid samples were prepared and weighted up using the same concentration of various weighting materials including barite, micromax, ilmenite, and hematite. The characteristics of the used weighting agents' (particle size distribution and mineralogy) were measured. Subsequently, the rheological properties of the drilling fluid were obtained using a Fann viscometer at 80°F. The filtration test was carried out at 200°F and 300 psi differential pressure to form a filter cake over the sandstone core samples. The properties of the formed filter cake layer such as thickness, porosity, and permeability were determined. Furthermore, the typical properties of core samples including porosity and permeability were assessed before and after the filtration test. The displayed results confirmed that the plastic viscosity (PV), yield point (YP), and filter cake sealing properties were all significantly influenced by the ratio of the large to fine particle size (D 90 /D 10) of the weighting agents irrespective of the weighting material type. Among the examined weighting agents, barite showed novel potency to control both rheological and filter cake properties for 14 ppg drilling fluid. The results showed that D 90 /D 10 is a key factor for the PV and YP properties as increasing the D 90 /D 10 ratio caused PV increase and YP decrease, which indicated that the interaction among the loaded weighting materials in the drilling fluid dominated its viscosity.
A Combined Barite–Ilmenite Weighting Material to Prevent Barite Sag in Water-Based Drilling Fluid
Materials
Barite sag is a serious problem encountered while drilling high-pressure/high-temperature (HPHT) wells. It occurs when barite particles separate from the base fluid leading to variations in drilling fluid density that may cause a serious well control issue. However, it occurs in vertical and inclined wells under both static and dynamic conditions. This study introduces a combined barite–ilmenite weighting material to prevent the barite sag problem in water-based drilling fluid. Different drilling fluid samples were prepared by adding different percentages of ilmenite (25, 50, and 75 wt.% from the total weight of the weighting agent) to the base drilling fluid (barite-weighted). Sag tendency of the drilling fluid samples was evaluated under static and dynamic conditions to determine the optimum concentration of ilmenite which was required to prevent the sag issue. A static sag test was conducted under both vertical and inclined conditions. The effect of adding ilmenite to the drillin...
Single stage filter cake removal of barite weighted water based drilling fluid
Journal of Petroleum Science and Engineering, 2017
The removal of barite filter cake is a challenging problem because the conventional filter cake removal treatments that use hydrochloric acid (HCl) or chelating agents were ineffective in dissolving barite containing filter cakes. Barite, or barium sulfate, is insoluble in water and acids such as HCl, formic, citric, and acetic acids. Also barite has very low solubility in chelating agents such as Ethylene diamine tetra acetic acid (EDTA) and Diethylene triamine penta acetic acid (DTPA). The present study focuses on developing new formulation to remove the barite filter cake. The removal formulation consists of chelating agents such as Diethylene Triamine Penta acetic Acid (DTPA), converting agent or catalyst, and polymer breaker (Enzyme). Solubility tests of industrial barite and solids collected from de-sanders during well flow back were conducted to develop barite removing solvent. Actual barite drilling fluid samples were collected from the field during drilling a high pressure high temperature deep gas well. The performance of the designed formulation was examined to remove the filter cake formed by real drilling fluid samples collected during drilling operations using High Pressure High Temperature cell (HPHT). Based on the result of this work the filter cake removing formulation dissolved more than 90% of the filter cake formed by real barite drilling fluid in a single stage within 24 hours. The removal formulation consists of high pH potassium base DTPA of 20% wt concentration, enzyme as a polymer degrading agent, and one of the following converting/catalytic agents (potassium carbonate, potassium formate, or potassium chloride). The use of converting agents increased the barite solubility from 67% to 95%.
Prevention of hematite settling using synthetic layered silicate while drilling high-pressure wells
Arabian Journal of Geosciences, 2020
Hematite (Fe 2 O 3) is used as a weighting material to increase the density of the drilling fluid. Hematite has a higher density (5.05 g/cm 3) compared with barite (4.2 g/cm 3). Because of the high specific gravity and particle size, hematite can separate and settle down at higher temperatures (> 250°F). The objective of this paper is to assess the usage of laponite which is synthetic layered silicate to solve the settling of hematite particles in water-based mud (WBM). Laponite was added to the WBM in different concentrations 0, 0.25, 0.5, 0.75, and 1 lb./bbl. Static and dynamic sag tests were performed to determine the optimum quantity of laponite. The viscoelastic and rheology properties were evaluated to compare between WBM-blank and WBMlaponite. The filtration test was performed at 250°F and 300-psi pressure difference to assess the effect of adding laponite on the filter cake thickness and filtration volume. The results showed that adding 1 lb./bbl of laponite was enough to eliminate the sag issue in both vertical and 45°inclination. The sag factor was reduced from 0.594 to 0.502 at the vertical condition and from 0.62 to 0.51 for the 45°inclined condition. For the dynamic sag, the viscometer sag shoe test (VSST) decreased from 2.1 to 0.21 lb./gal after adding 1 lb./bbl of laponite. It was observed that the apparent viscosity (AV) and yield point (YP) increased by 16% and 33% after adding 1 lb./bbl of the laponite respectively, while there was no change in plastic viscosity (PV) which resulted in increasing the YP/PV ratio which is a good indication of fluid stability and better hole cleaning performance. For the filtration properties, there was no significant change in filter cake thickness and filtration volume.
The Role of Drilled Formation in Filter Cake Properties Utilizing Different Weighting Materials
ACS Omega
The filter cake formed during a filtration process plays a vital role in the success of a drilling operation. There are several factors affecting the filter cake build-up such as drilled formation, drilling fluid properties, and well pressure and temperature. The collective impact of these two factors (i.e., formation and the drilling fluid) on the filter cake build-up needs to be fully investigated. In this study, two types of formations represented as limestone and sandstone were used with different weighting materials to assess and compare their impact on the filter cake properties, filtration behavior, and solid invasion. The used weighting materials are manganese tetroxide, ilmenite, barite, and hematite. The filter cake was formed under a temperature of 200°F and differential pressure of 300 psi. Nuclear magnetic resonance spectroscopy was employed to explore the pore structure of the used core samples. The results showed that the properties (i.e., shape and dimensions) of the different weighting materials are the dominant factors compared to the formation characteristics in most of the investigated filter cake properties. Nevertheless, the formation properties, namely, the permeability and pore structure, have a somehow higher contribution when it comes to the filter cake porosity and thickness. For solid invasion, there were no clear results about the main factor contributing to this issue.
Sustainability
Drilling high-pressure high-temperature (HPHT) wells requires a special fluid formulation that is capable of controlling the high pressure and is stable under the high downhole temperature. Barite-weighted fluids are common for such purpose because of the good properties of barite, its low cost, and its availability. However, solids settlement is a major problem encountered with this type of fluids, especially at elevated downhole temperatures. This phenomenon is known as barite sag, and it is encountered in vertical and directional wells under static or dynamic conditions leading to serious well control issues. This study aims to evaluate the use of barite-ilmenite mixture as a weighting agent to prevent solids sag in oil-based muds at elevated temperatures. Sag test was conducted under static conditions (vertical and inclined) at 350 °F and under dynamic conditions at 120 °F to determine the optimum ilmenite concentration. Afterward, a complete evaluation of the drilling fluid was...
AADE-12-FTCE-23 Hindrance Effect on Barite Sag in Non-Aqueous Drilling Fluids
2012
The phenomenon of barite sag requires better understanding, especially in non-aqueous drilling fluids (NAF) where it causes density variations leading to well stability issues. Sag is considered a dynamic phenomenon that can be severe in highly deviated and complex wells. Tackling this challenge calls for experimental/empirical methods to predict barite sag for different fluid compositions and well environments. Hindered particle settling caused by presence of nearby particles is usually a strong function of particle concentration (φ) in the suspension. Empirical methods to predict hindered settling have been well established for suspensions with Newtonian liquids as continuous phase. Here, these empirical methods for hindered settling have been extended to NAF with varied barite concentrations (mud weights). To develop the hindrance model, experimental data on sag rate U (mm/hr) in a NAF is obtained from the Dynamic High Angle Sag Tester (DST) at chosen conditions of temperature, p...
Experimental investigation on barite sag under flowing condition and drill pipe rotation
Journal of Petroleum Exploration and Production Technology
Using drilling fluids with optimum density is one of the most important approaches to stabilize the pressure of the bottom formation and prevent blowout through the drilling process. One of the common methods for this purpose is adding some additives with high specific gravity to the drilling fluid to tune its density. Among the possible chemicals, barite and hematite with the density of 4.2 and 5.2 g/cc are the most common additives. Unfortunately, although the application of these additives is advantageous, they have some drawbacks which the most important one is separation and settlement of solid phase called barite sag. The barite sag comes from barite, or other dense materials particles deposition resulted in undesired density fluctuations in drilling fluid can lead to mud loss, well control problems, poorly cementing and even pipe sticking which occurs in severe cases. With respect to these concerns, the current investigation is concentrated to obtain the relation between the ...
Suitability of Some Nigerian Barites in Drilling Fluid Formulations
Petroleum Science and Engineering, 2019
In order to counterbalance the formation pressure, the drilling mud is weighted up using a chemical additive, usually Barite. The usability of locally sourced Nigerian Barites on the major types of drilling fluids in conventional conditions is presented. Water-Based mud, Oil-Based mud and Synthetic-Based mud formulations with locally sourced Barite were tested according to the American Petroleum Institute recommended practices. Hole cleaning capabilities of the formulations by the use of Cutting Carrying Index (CCI) and Cutting Concentration (CC) as indicators showed that Osina, Gabu and Obubra Nigerian Barites are suitable for use as drilling fluid additives; with Cutting Carrying Index in the range of 23.27 to 120.54 for Water-Based mud, 0.89 to 3.98 for Oil-Based mud and 0.45 to 1.13 for Synthetic-Based mud. The Cutting Concentration of average of 4.15 vol. % at 355gpm and 300ft/hr ROP for Water-Based mud, Oil-Based mud and Synthetic-Based mud, with MAXROP of 364ft/hr under the same conditions was recorded. Moreso, laminar flow regime in the annulus was predicted for all the mud types under the same conditions and temperatures specified, based on a MATLAB programme developed to perform the computation. Cutting Carrying Index for water based mud decreased from ambient, 120°F, 180°F to 240°F compared with API mud used as control sample.