Performance Evaluation of a Highly Inhibitive Water-Based Drilling Fluid for Ultralow Temperature Wells

2017 ◽  
Vol 140 (1) ◽  
Author(s):  
Xin Zhao ◽  
Zhengsong Qiu ◽  
Mingliang Wang ◽  
Weian Huang ◽  
Shifeng Zhang
Keyword(s):  
Drilling Fluid ◽  
Hydrate Formation ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Offshore Drilling ◽  
Ultralow Temperature ◽  
Water Based ◽  
Drilling Operations ◽  
Inhibition Performance ◽  
Static Conditions

Drilling fluid with proper rheology, strong shale, and hydrate inhibition performance is essential for drilling ultralow temperature (as low as −5 °C) wells in deepwater and permafrost. In this study, the performance of drilling fluids together with additives for ultralow temperature wells has been evaluated by conducting the hydrate inhibition tests, shale inhibition tests, ultralow temperature rheology, and filtration tests. Thereafter, the formulation for a highly inhibitive water-based drilling fluid has been developed. The results show that 20 wt % NaCl can give at least a 16-h safe period for drilling operations at −5 °C and 15 MPa. Polyalcohol can effectively retard pore pressure transmission and filtrate invasion by sealing the wellbore above the cloud point, while polyetheramine can strongly inhibit shale hydration. Therefore, a combination of polyalcohol and polyetheramine can be used as an excellent shale stabilizer. The drilling fluid can prevent hydrate formation under both stirring and static conditions. Further, it can inhibit the swelling, dispersion, and collapse of shale samples, thereby enhancing wellbore stability. It has better rheological properties than the typical water-based drilling fluids used in onshore and offshore drilling at −5 °C to 75 °C. In addition, it can maintain stable rheology after being contaminated by 10 wt % NaCl, 1 wt % CaCl2, and 5 wt % shale cuttings. The drilling fluid developed in this study is therefore expected to perform well in drilling ultralow temperature wells.

scholarly journals Laponite: a promising nanomaterial to formulate high-performance water-based drilling fluids

2020 ◽  
Author(s):  
Xian-Bin Huang ◽  
Jin-Sheng Sun ◽  
Yi Huang ◽  
Bang-Chuan Yan ◽  
Xiao-Dong Dong ◽  
...  
Keyword(s):  
High Performance ◽  
Drilling Fluid ◽  
Nitrogen Adsorption ◽  
Drill String ◽  
Wellbore Stability ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Mechanism Analysis ◽  
Water Based ◽  
Inhibition Performance

Abstract High-performance water-based drilling fluids (HPWBFs) are essential to wellbore stability in shale gas exploration and development. Laponite is a synthetic hectorite clay composed of disk-shaped nanoparticles. This paper analyzed the application potential of laponite in HPWBFs by evaluating its shale inhibition, plugging and lubrication performances. Shale inhibition performance was studied by linear swelling test and shale recovery test. Plugging performance was analyzed by nitrogen adsorption experiment and scanning electron microscope (SEM) observation. Extreme pressure lubricity test was used to evaluate the lubrication property. Experimental results show that laponite has good shale inhibition property, which is better than commonly used shale inhibitors, such as polyamine and KCl. Laponite can effectively plug shale pores. It considerably decreases the surface area and pore volume of shale, and SEM results show that it can reduce the porosity of shale and form a seamless nanofilm. Laponite is beneficial to increase lubricating property of drilling fluid by enhancing the drill pipes/wellbore interface smoothness and isolating the direct contact between wellbore and drill string. Besides, laponite can reduce the fluid loss volume. According to mechanism analysis, the good performance of laponite nanoparticles is mainly attributed to the disk-like nanostructure and the charged surfaces.

Machine Learning Applications in Drilling Fluid Engineering: a Review

2021 ◽  
Author(s):  
Sercan Gul
Keyword(s):  
Machine Learning ◽  
Oil And Gas ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Fluid Mud ◽  
Surface Cooling ◽  
Real Time Analysis ◽  
Machine Learning Applications ◽  
Drilling Operations

Abstract Drilling fluid (mud) serves various purposes in drilling operations, the most important being the primary well control barrier to prevent kicks and blowouts. Other duties include, but not limited to, maintaining wellbore stability, removing and transporting formation cuttings to the surface, cooling and lubricating downhole tools, and transmitting hydraulic energy to the drill bit. Mud quality is therefore related to most of the problems in drilling operations either directly or indirectly. The physics-based models used in the industry with drilling fluid information (i.e., cuttings transport, well hydraulics, event detection) are computationally expensive, difficult to integrate for real-time analysis, and not always applicable for all drilling conditions. For this reason, researchers have shown extensive interest in machine learning (ML) approaches to alleviate their fluid-related problems. In this study, a comprehensive review of the abundant literature on the various applications of ML in oil and gas operations, concentrating mainly on drilling fluids, is presented. It was shown that leveraging state-of-the-art supervised and unsupervised ML methods can help predict or eliminate most fluid-related issues in drilling. The review discusses various ML methods, their theory, applications, limitations, and achievements.

Sodium Silicate Based Drilling Fluid Application in Gulf of Thailand to Stabilise Wellbore: A Case Study

2021 ◽  
Author(s):  
Waleepon Sukarasep ◽  
Rahul Sukanta Dey ◽  
Visarut Phonpuntin
Keyword(s):  
Sodium Silicate ◽  
High Performance ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Gulf Of Thailand ◽  
Hole Cleaning ◽  
Water Based ◽  
Wellbore Strengthening ◽  
Effective Seal

Abstract Sodium Silicate were first used in water-based drilling fluids to stabilize claystone formations in the 1930's, but found favour in the 1990's in high performance, non dispersed water based systems for drilling problematic claystone formations as an alternative to oil-based drilling fluids. In Bongkot South field, Gulf of Thailand, sodium silicate-based drilling fluid (SSBDF) were used with mixed success in shallow gas drilling. Typically, platform WP-33, the claystone formation of the 12¼" section were drilled with 5% v/v Sodium Silicate in the water based drilling fluid together with excessive circulation as intention to improve hole cleaning frequently result in a wellbore that was overgauge by upto 18.9% in some case. This led to further hole cleaning problem that also compromised cement job quality. A further 6 well campaign on WPS-16 required a re-evaulation of the SSBDF coupled to an understanding of the wellbore instability mechanisms that leads to hole enlargement. To overcome better wellbore stability, sodium silicate has been designed by increased concentration to 8% v/v sodium silicate treated drilling fluid showed optimal design for application base on application of SSBDF has been used on platform WP-11 in 2002. Rheology, hydraulic and flow regime was adjusted for laminar flow that reduced the erosion of fragile claystone formation in the wellbore. The revised SSBDF formulation at WPS-16 result in a significant reduction of hole enlargement to 3.2% in the claystone section through a combination of chemicals and mechanical inhibition that contribute improved hole cleaning. The addition of wellbore strengthening material also provide an effective seal to minimize gas invasion. This paper describes the field trials in the Gulf of Thailand drilled with revised sodium sodium silicate based drilling fluid, the use of wellbore strengthening materials to manage gas influxes, better drilling practice and hydraclic simulation concluded that high performance water based drilling fluid of this nature have wider application where oil-base drilling fluid have traditionally been used.

The Influence of SiO2 and TiO2 Nanoparticles on the Properties of Water-Based Mud

2017 ◽  
Author(s):  
Petar Mijić ◽  
Nediljka Gaurina-Međimurec ◽  
Borivoje Pašić
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Drilling Mud ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Water Based ◽  
Fluid Properties

About 75% of all formations drilled worldwide are shale formations and 90% of all wellbore instability problems occur in shale formations. This increases the overall cost of drilling. Therefore, drilling through shale formations, which have nanosized pores with nanodarcy permeability still need better solutions since the additives used in the conventional drilling fluids are too large to plug them. One of the solutions to drilling problems can be adjusting drilling fluid properties by adding nanoparticles. Drilling mud with nanoparticles can physically plug nanosized pores in shale formations and thus reduce the shale permeability, which results in reducing the pressure transmission and improving wellbore stability. Furthermore, the drilling fluid with nanoparticles, creates a very thin, low permeability filter cake resulting in the reduction of the filtrate penetration into the shale. This thin filter cake implies high potential for reducing the differential pressure sticking. In addition, borehole problems such as too high drag and torque can be reduced by adding nanoparticles to drilling fluids. This paper presents the results of laboratory examination of the influence of commercially available nanoparticles of SiO2 (dry SiO2 and water-based dispersion of 30 wt% of silica), and TiO2 (water-based dispersion of 40 wt% of titania) in concentrations of 0.5 wt% and 1 wt% on the properties of water-based fluids. Special emphasis is put on the determination of lubricating properties of the water-based drilling fluids. Nanoparticles added to the base mud without any lubricant do not improve its lubricity performance, regardless of their concentrations and type. However, by adding 0.5 wt% SiO2-disp to the base mud with lubricant, its lubricity coefficient is reduced by 4.6%, and by adding 1 wt% TiO2-disp to the base mud with lubricant, its lubricity coefficient is reduced by 14.3%.

Filter Cake Properties of Water-Based Drilling Fluids Under Static and Dynamic Conditions Using Computed Tomography Scan

2013 ◽  
Vol 135 (4) ◽  
Author(s):  
Salaheldin Elkatatny ◽  
Mohamed Mahmoud ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Computed Tomography ◽  
Filter Cake ◽  
Drilling Fluid ◽  
Filter Press ◽  
Filter Medium ◽  
Drilling Fluids ◽  
Dynamic Conditions ◽  
Water Based ◽  
Porosity And Permeability ◽  
Static Conditions

Previous studies considered the water-based drilling fluid filter cake as homogenous, containing one layer with an average porosity and permeability. The filter cake was recently proved to be heterogeneous, containing two layers with different properties (thickness, porosity and permeability). Heterogeneity of the filter cake plays a key role in the design of chemical treatments needed to remove the filter cake. The objectives of this study are to describe filter cake buildup under static and dynamic conditions, determine change in the filter medium properties, and obtain the local filtration properties for each layer in the filter cake. A high pressure high temperature (HPHT) filter press was used to perform the filtration process at 225 °F and 300 psi. A CT (computed tomography) scanner was used to measure the thickness and porosity of the filter cake. The results obtained from the CT scan showed that under static conditions, the formation of filter cake changed from compression to buildup; while under dynamic conditions, the filter cake was formed under continuous buildup. The CT results explained the changes in the thickness and porosity of each layer of the filter cake with time. The CT scans showed the change in the properties of the ceramic disk, such as porosity and permeability, which affect the calculation of the filter cake permeability. The change of the properties of the filter medium was ignored in previous studies.

scholarly journals An Assessment of the Causes of Wellbore Instability and Stuck Pipe Occurrences in an Offshore Field, Niger Delta, Nigeria

2020 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Cation Exchange ◽  
Niger Delta ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Swelling Potential ◽  
Offshore Drilling ◽  
Wellbore Instability ◽  
Clay Swelling ◽  
Drilling Operations ◽  
Cationic Exchange

Wellbore instability and consequential stuck pipe issues are a common challenge associated with offshore drilling. Usually, the effect of wellbore instability is an increase in nonproductive time, possible loss of tools and costly drilling operations. Hence, there is a need for wellbore stability analyses before and during drilling operations. In “Agaza Field”, offshore Niger Delta, wellbore instability problems were encountered at various depths between 3,696-4,270 ft.; 5,000-5,425 ft. and 7,600-8000 ft. intervals. Sixty-five ditch-cutting samples and composite log plots obtained from both wells were and analyzed to determine the clay swelling potential and the cationic exchange between the formation and the drilling fluid as well as causes of formation instability. Agaza-1 well showed evidence of tight hole at intervals between 4,200 and 7,600 ft. In Agaza-2, there were indications of wellbore stresses from 1,908 ft. to 2,030 ft. However, deeper than 4,225ft depth, high fluctuation of pore pressure coincided with wellbore instability between 4,810 ft. and 5,200 ft. The principal clay minerals present within the formations are Illite, Smectite and Smectite/Illite interlayered types. Result of the cation exchange analysis showed that high concentration of calcium and sodium in the shale is responsible for high dissociation of the constituent minerals hence making the shales unstable. Analysis has shown that samples at some intervals from both wells are associated with high swelling potential while average cation exchange value is 40 meq/100g. Therefore, the primary cause of wellbore instability and stuck pipe within the studied intervals are attributed to high swelling and reactivity over time due to fluidformation interaction. Keywords: Clay cationic exchange, Clay swelling potential, Offshore drilling challenges, Reactive shales. African

Effect of LCM Fibers on the Rate of THF-Water Clathrate Hydrate Growth in Water-Based Drilling Fluids

2019 ◽  
Author(s):  
James L. Nielsen ◽  
Syed Y. Nahri ◽  
Wei Zhao ◽  
Panfeng Wei ◽  
Yuanhang Chen
Keyword(s):  
Gas Hydrates ◽  
Drilling Fluid ◽  
Molar Ratio ◽  
Drilling Fluids ◽  
Lost Circulation ◽  
Water Based ◽  
Control Event ◽  
Significant Change ◽  
Time Required ◽  
Static Conditions

Abstract This study investigates how different sized fibers used commonly as Lost Circulation Material (LCM) change the time required for induction and agglomeration of natural gas hydrates in drilling fluids using laboratory experimentally obtained data. Three different sizes of LCM fibers, fine, medium and coarse, were studied to observe how the size of each type of fiber affects the rate of hydrates growth. THF-Water clathrate hydrates were used as a model for hydrate growth at standard pressure conditions using a 20:80 molar ratio of THF to water. The concentrations of LCM fibers tested varied between 1–3% by weight. Each type of fiber was tested individually at −6 °C, −3 °C, and 0 °C and monitored for changes in hydrate induction and agglomeration rates. Tests were repeated using water-based drilling fluids using bentonite as the primary viscosifier and barite as a weighting agent to test 10, 12, and 14 ppg fluids. Fibers were tested under static conditions to identify changes in the nucleation and agglomeration rates for each. The rates of hydrate nucleation between samples of THF-Water and LCM fibers and each sample of water-based drilling fluid with LCM fibers was found to be consistent with no statistically significant change in rate being observed due to the fibers present. However, we observed a significant change in the rate of agglomeration that was dependent on the size and concentration of the fiber particles. We identified that fine fibers provided the most significant increase in the rate of agglomeration followed by medium and coarse fibers, respectively, with increasing LCM fiber concentrations. Compared to control samples, using fibers produced initial hydrate agglomeration around the freely suspended fibers. Due to their proximity to other fibers with hydrates developing around them, the hydrates were able to form very large free moving crystals in the solution before completely agglomerating and forming a solid plug. The results and conclusions provide new insights and guidance in drilling fluids and LCM design for offshore deep-water drilling. Gas hydrates can potentially develop and agglomerate along in the BOP and kill/choke lines during a well control event, as what is suspected as what happened in Macondo blowout where a considerable amount LCMs were used during drilling and as a spacer during a negative pressure test.

scholarly journals Effect of silica nano particles on the rheological and HTHP filtration properties of environment friendly additive in water-based drilling fluid

2021 ◽  
Author(s):  
Ved Prakash ◽  
Neetu Sharma ◽  
Munmun Bhattacharya
Keyword(s):  
Drilling Fluid ◽  
Cost Effective ◽  
Vital Role ◽  
Nano Particles ◽  
Rheological Parameters ◽  
Drilling Fluids ◽  
Filtration Loss ◽  
Water Based ◽  
Drilling Operations ◽  
Filtration Properties

AbstractRheological and filtration properties of drilling fluid contribute a vital role in successful drilling operations. Rheological parameters such as apparent viscosity (AV), plastic viscosity (PV), yield point (YP) and gel strength of drilling fluids are very essential for hydraulic calculations and lifting of drill cuttings during the drilling operation. Control of filtration loss volume is also very important for cost effective and successful drilling operations. Therefore, the main goal of this research is to improve the rheological and filtration properties of Grewia Optiva fibre powder (GOFP) by using 30–50 nm size of silica nano particles (SNP) in water-based drilling fluid. The experimental outcomes revealed that after hot rolling of mud samples at 100 °C for 16 h, the low pressure-low temperature (LPLT) and high pressure-high temperature (HPHT) filtration loss of GOFP additives was improved, after the addition of SNP on it. The mixture of 5% GOFP + 4% SNP has reduced the LPLT and HPHT filtration loss of drilling fluid by 74.03 and 78.12%, respectively, as compared to base mud. Thus, it was concluded that after the addition of 0.4% SNP, the LPLT and HPHT filtration control ability of GOFP additive in WBM were increased by 17.6 and 15%, respectively. The rheological parameters such as AV, PV, YP and gelation of drilling fluids were also improved by the addition of GOFP + SNP mixture in the base mud. Therefore, the implementation of GOFP + SNP mixture in water-based mud showed auspicious results which reaffirm the feasibility of using them in the successful drilling operations.

A Novel Self-Photodegradation Drilling Fluids Under Near-Infrared Light Irradiation with Preferable Wellbore Stability

2021 ◽  
Author(s):  
Jiafeng Jin ◽  
Kaihe Lv ◽  
Jinsheng Sun ◽  
Yingrui Bai ◽  
Jingping Liu ◽  
...  
Keyword(s):  
Organic Contaminants ◽  
Near Infrared ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Wettability Alteration ◽  
Infrared Light ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Gas Drilling ◽  
Drilling Operations

Abstract The ever-mounting drilling operations of the petroleum industry has been accompanied by tremendous wasted drilling fluid, Polycyclic Aromatic Hydrocarbons (PAHs) in which pose a huge threat to the health of human and ecosystem. Varying approaches have been proposed to remediate the damage caused by wasted drilling fluid, among which photocatalysis has been one of the most promising approaches for organic contaminants removal. The latest investigation shows that Bi2WO6 decorated on hydrophobic CNT can remove up to 80 % organic contaminant within a short time, exhibiting a preferable photocatalytic performance. Moreover, this hydrophobic CNT can play a vital role in stabilizing the wellbore due to its excellent water repellent. The objective of the study was to find out the effect of Bi2WO6 modified hydrophobic CNT on the PAHs photodegradation and wellbore stability in the process of drilling. Bi2WO6 as a near-infrared driven photocatalyst has attracted worldwide attention due to its preferable oxygen vacancy and quantum efficiency. However, the application of Bi2WO6 was impeded by the low migration efficiency of photo-generated carriers. The combination of Bi2WO6 and composite with good conductivity has been an effective method to resolve this problem. The instability of wellbore caused by shale hydration during oil and gas drilling operations also brings a huge challenge. In this study, a photocatalyst with wellbore stabilization capacity is achieved by hydrophobic CNT modified via Bi2WO6 sheet with nano-size. The fluid loss and wettability property were measured to evaluate the wellbore stabilization capacity of this novel agent. Meanwhile, photodegradation experiments and pathway analysis were conducted to evaluate the effect of photodegradation by Bi2WO6/CNT on the organic contaminants. Data of photodegradation indicated that the PAHs can be degraded up to 80% after treated by Bi2WO6/CNT, the migration efficiency of photogenerated carriers improved significantly. A slight decrease in fluid loss and distinctive increase in viscosity can be observed after treated with 0.3% Bi2WO6/CNT solution. The results of the rheology test verified that the photocatalyst has little effect on the rheological properties of drilling fluid. The result of SEM indicated that this novel Bi2WO6/CNT composite with a bombax structure can absorb preferentially organic contaminants, which is good at in-situ photodegradation and prevention of water invasion. To sum up, PAHs in wasted drilling fluids can be photodegraded by the novel Bi2WO6 nano-sheet modified CNT, and the stability of wellbore can also be significantly enhanced due to wettability alteration.

scholarly journals Prevention of Barite Sag in Water-Based Drilling Fluids by A Urea-Based Additive for Drilling Deep Formations

2020 ◽  
Vol 12 (7) ◽  
pp. 2719 ◽  
Author(s):  
Abdelmjeed Mohamed ◽  
Saad Al-Afnan ◽  
Salaheldin Elkatatny ◽  
Ibnelwaleed Hussein
Keyword(s):  
Base Fluid ◽  
Drilling Fluid ◽  
Gel Strength ◽  
Optimum Concentration ◽  
Drilling Fluids ◽  
Filtration Performance ◽  
Water Based ◽  
The Stability ◽  
Static Conditions ◽  
The Impact

Barite sag is a challenging phenomenon encountered in deep drilling with barite-weighted fluids and associated with fluid stability. It can take place in vertical and directional wells, whether in dynamic or static conditions. In this study, an anti-sagging urea-based additive was evaluated to enhance fluid stability and prevent solids sag in water-based fluids to be used in drilling, completion, and workover operations. A barite-weighted drilling fluid, with a density of 15 ppg, was used with the main drilling fluid additives. The ratio of the urea-based additive was varied in the range 0.25–3.0 vol.% of the total base fluid. The impact of this anti-sagging agent on the sag tendency was evaluated at 250 °F using vertical and inclined sag tests. The optimum concentration of the anti-sagging agent was determined for both vertical and inclined wells. The effect of the urea-additive on the drilling fluid rheology was investigated at low and high temperatures (80 °F and 250 °F). Furthermore, the impact of the urea-additive on the filtration performance of the drilling fluid was studied at 250 °F. Adding the urea-additive to the drilling fluid improved the stability of the drilling fluid, as indicated by a reduction in the sag factor. The optimum concentration of this additive was found to be 0.5–1.0 vol.% of the base fluid. This concentration was enough to prevent barite sag in both vertical and inclined conditions at 250 °F, with a sag factor of around 0.5. For the optimum concentration, the yield point and gel strength (after 10 s) were improved by around 50% and 45%, respectively, while both the plastic viscosity and gel strength (after 10 min) were maintained at the desired levels. Moreover, the anti-sagging agent has no impact on drilling fluid density, pH, or filtration performance.

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