Anti-Collapse Drilling Fluids for the Cretaceous Scientific Drilling in Songliao Basin, China: A Case Study

2012 ◽  
Vol 170-173 ◽  
pp. 1196-1201
Author(s):  
Ji Hua Cai ◽  
Xiao Ming Wu ◽  
Sui Gu
Keyword(s):  
Drilling Fluid ◽  
Songliao Basin ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Shale Formations ◽  
Scientific Drilling ◽  
Fluid Systems ◽  
Managed Pressure Drilling ◽  
Shale Formation

CCSD-SK1 well was the first Cretaceous scientific drilling well in the world, locating in Songliao basin, Northeast China. It included main well (also called north well) and south well. This paper introduced the anti-collapse drilling fluid technology in main well where the desired continuous coring section was from 164.77 m to 1792.00 m. Continuous technical barriers challenged the intelligence of drilling engineers of this project. First, preserving the wellbore stability was the most critical aspect of continuous core drilling. From top to bottom, the unconsolidated sandstone in the Quaternary super stratum, the water sensitive shale in the Sifangtai group and upper stratum of the Nenjiang group, and the brittle shale of under stratum of the Nenjiang group increased the difficulty of anti-collapse drilling fluid technology. Water invasion into the shale formation often weakens the wellbore and causes problems such as wellbore collapse, shale destabilization and stuck pipe. Fluids should be designed to mitigate these shale problems. Secondly, the openhole strategy imposed the difficulty of maintaining wellbore stability in the second open process (from 245.00 m to the bottom). Finally, the total expense of the well was only one fifth of south well, which was drilled by an oilfield drilling contractor. To overcome these technical challenges, not only different drilling fluid systems such as PAM drilling fluid, DFD-LG-CMC drilling fluid and DFD-NH4HPAN-SAKH drilling fluid were adopted separately, but also technology of feasible viscosity and managed pressure drilling were used. A total of 395 trips had been run in this Cretaceous scientific drilling well and no accidents even dangerous cases occurred. The experience of CCSD-SK1 (main well) explored a successful way of employing economic drilling fluid to preceding similar scientific drilling projects in similar shale formations.

scholarly journals Experimental Investigation of Inhibitive Drilling Fluids Performance: Case Studies from United States Shale Basins

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5142
Author(s):  
Nabe Konate ◽  
Saeed Salehi
Keyword(s):  
Oil And Gas ◽  
Drilling Fluid ◽  
Gas Production ◽  
Drilling Fluids ◽  
Eagle Ford Shale ◽  
Oil And Gas Production ◽  
Shale Formations ◽  
Drilling Performance ◽  
Marine Shale ◽  
Fluid Systems

Shale formations are attractive prospects due to their potential in oil and gas production. Some of the largest shale formations in the mainland US, such as the Tuscaloosa Marine Shale (TMS), have reserves estimated to be around 7 billion barrels. Despite their huge potential, shale formations present major concerns for drilling operators. These prospects have unique challenges because of all their alteration and incompatibility issues with drilling and completion fluids. Most shale formations undergo numerous chemical and physical alterations, making their interaction with the drilling and completion fluid systems very complex to understand. In this study, a high-pressure, high-temperature (HPHT) drilling simulator was used to mimic real time drilling operations to investigate the performance of inhibitive drilling fluid systems in two major shale formations (Eagle Ford Shale and Tuscaloosa Marine Shale). A series of drilling experiments using the drilling simulator and clay swelling tests were conducted to evaluate the drilling performance of the KCl drilling fluid and cesium formate brine systems and their effectiveness in minimizing drilling concerns. Cylindrical cores were used to mimic vertical wellbores. It was found that the inhibitive muds systems (KCl and cesium formate) provided improved drilling performance compared to conventional fluid systems. Among the inhibitive systems, the cesium formate brine showed the best drilling performances due to its low swelling rate and improved drilling performance.

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%.

scholarly journals New insight on studying the effect of both chemical sensitivity and rock mechanical properties in shale formation to minimize wellbore instability problems

2020 ◽  
Vol 205 ◽  
pp. 03012
Author(s):  
Mohammad H. Alqam ◽  
Hazim H. Abass ◽  
Abdullah M. Shebatalhmad
Keyword(s):  
Drilling Fluid ◽  
Wellbore Stability ◽  
High Porosity ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Testing Procedures ◽  
Shale Formation ◽  
Rock Mechanical Properties ◽  
Core Volume ◽  
Shale Permeability

Historically, many of the wells drilled in in shale formations have experienced a significant rig downtime due to wellbore instabilities. Most of the instability problems originated from the encountered shale formations. The objectives of this study include (1) to measure the properties governing shale strength and drilling fluid/shale interaction, and (2) to establish a reliable and efficient rock mechanical testing procedures related to wellbore stability. Preserved shale core has been recovered from shale formation and special core handling procedure was implemented. Mineral oil was used for plugging and core preservation. Rock mechanical characterization was conducted on core samples using both XRD/SEM techniques to study the core mineralogy. In addition, shale permeability was determined by two methods: flow testing and pressure transition methods. The results indicated that shale has high percentage of quartz (30-40%) which causes the shale to have high porosity and high permeability. The unconfined compressive strength of shale is very low which any drilling fluid that contains water phase further reduces. The Young’s modulus is very low which makes near wellbore deformation high. Based on the shale swelling testing, the all-oil fluid show no volume change occurred to the shale. When the same shale was exposed to the 7% KCl, about 16% increase in core volume occurred in 48 hours. This means that all samples allowed the water to flow into the shale formation.

scholarly journals Borehole Stability in Shale Formation: Modeling the Effects of Molecular Weight and Concentration of Polymers in the Drilling Fluids Formulation

2014 ◽  
Vol 5 (1) ◽  
pp. 260-270
Author(s):  
Khoshniyat A ◽  
Shojaei M. ◽  
Jarahian K. ◽  
Mirali M. ◽  
Ghorashi S. ◽  
...  
Keyword(s):  
Molecular Weight ◽  
Reflection Coefficient ◽  
Drilling Fluid ◽  
Exchange Capacity ◽  
Oil Field ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Drilling Process ◽  
Borehole Stability ◽  
Shale Formation

A new experimental model was developed to predict the role of special polymeric additives, in the drilling fluid formulation, on the wellbore stability in shale formation. The shale formation was regarded as a non-ideal membrane and the effects of various characteristics of the added polymers were studied on the membrane reflection coefficient. The model was applied to unique field data from the oil field in south of Iran, including clay structure, cation exchange capacity (CEC), density and porosity of the shale. The results, using various polyglycols and polyacrylamides as the polymeric additive, showed that the structure of the polymeric chains e.g. type and content of ionic segments had significant effect on their adsorption mechanism and its strength.  It was concluded that increasing the molecular weight of the polymer chains decreased the rate and amount of the adsorption due to the increasing of the entanglements between the chains which in turn limited their mobility. So, adsorption of the polymeric material on the shale had significant impress on its performance as a membrane by increasing the shale reflection coefficient enhancing its stability during drilling process. Finally, the developed model results were in good agreement by experimental test results which was done in a specific shale stability set up.

ENVIRONMENTAL DRILLING SOLUTIONS ON THE POLYMERIC BASIS

2020 ◽  
Author(s):  
E.A. Flik ◽  
◽  
Y.E. Kolodyazhnaya
Keyword(s):  
Oil And Gas ◽  
Drilling Fluid ◽  
Oil And Gas Industry ◽  
Environmental Safety ◽  
Drilling Fluids ◽  
Gas Industry ◽  
Fluid Systems ◽  
Water Based

The article assesses the environmental safety of drilling fluids that are currently widely used in the oil and gas industry. It shows active development of water-based drilling fluid systems using xanthan biopolymer.

scholarly journals Laboratory Study on Core Fracturing Simulations for Wellbore Strengthening

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-18 ◽  
Author(s):  
Biao Ma ◽  
Xiaolin Pu ◽  
Zhengguo Zhao ◽  
Hao Wang ◽  
Wenxin Dong
Keyword(s):  
Bearing Capacity ◽  
Laboratory Study ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Lost Circulation ◽  
The Core ◽  
Fracture Pressure ◽  
Fluid Systems ◽  
Fracturing Process ◽  
Wellbore Strengthening

The lost circulation in a formation is one of the most complicated problems that have existed in drilling engineering for a long time. The key to solving the loss of drilling fluid circulation is to improve the pressure-bearing capacity of the formation. The tendency is to improve the formation pressure-bearing capacity with drilling fluid technology for strengthening the wellbore, either to the low fracture pressure of the formation or to that of the naturally fractured formation. Therefore, a laboratory study focused on core fracturing simulations for the strengthening of wellbores was conducted with self-developed fracture experiment equipment. Experiments were performed to determine the effect of the gradation of plugging materials, kinds of plugging materials, and drilling fluid systems. The results showed that fracture pressure in the presence of drilling fluid was significantly higher than that in the presence of water. The kinds and gradation of drilling fluids had obvious effects on the core fracturing process. In addition, different drilling fluid systems had different effects on the core fracture process. In the same case, the core fracture pressure in the presence of oil-based drilling fluid was less than that in the presence of water-based drilling fluid.

Characterization of the Rheological Behavior of Drilling Fluids

2020 ◽  
Author(s):  
Eric Cayeux ◽  
Amare Leulseged
Keyword(s):  
Shear Rate ◽  
Rheological Behavior ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Shear Rates ◽  
Operation Conditions ◽  
Fluid Systems ◽  
Different Temperatures ◽  
The One ◽  
Shear Stress Response

Abstract It is nowadays well accepted that the steady state rheological behavior of drilling fluids must be modelled by at least three parameters. One of the most often used models is the yield power law, also referred as the Herschel-Bulkley model. Other models have been proposed like the one from Robertson-Stiff, while other industries have used other three-parameter models such as the one from Heinz-Casson. Some studies have been made to compare the degree of agreement between different rheological models and rheometer measurements but in most cases, already published works have only used mechanical rheometers that have a limited number of speeds and precision. For this paper, we have taken measurements with a scientific rheometer in well-controlled conditions of temperature and evaporation, and for relevant shear rates that are representative to normally encountered drilling operation conditions. Care has been made to minimize the effect of thixotropy on measurements, as the shear stress response of drilling fluids depends on its shear history. Measurements have been made at different temperatures, for various drilling fluid systems (both water and oil-based), and with variable levels of solid contents. Also, the shear rate reported by the rheometer itself, is corrected to account for the fact that the rheometer estimates the wall shear rate on the assumption that the tested fluid is Newtonian. A measure of proximity between the measurements and a rheological model is defined, thereby allowing the ranking of different rheological behavior model candidates. Based on the 469 rheograms of various drilling fluids that have been analyzed, it appears that the Heinz-Casson model describes most accurately the rheological behavior of the fluid samples, followed by the model of Carreau, Herschel-Bulkley and Robertson-Stiff, in decreasing order of fidelity.

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.

scholarly journals Experimental study of Zubair shale stability of east Baghdad oil field using different additives in water based mud

2019 ◽  
Vol 10 (3) ◽  
pp. 1215-1225
Author(s):  
Asawer A. Alwassiti ◽  
Mayssaa Ali AL-Bidry ◽  
Khalid Mohammed
Keyword(s):  
Drilling Fluid ◽  
Oil Field ◽  
Oil Fields ◽  
Drilling Fluids ◽  
Fluid Type ◽  
Wellbore Instability ◽  
Immersion Period ◽  
Shale Formation ◽  
Shale Recovery ◽  
Polymer Type

AbstractShale formation is represented as one of the challenge formations during drilling wells because it is a strong potential for wellbore instability. Zubair formation in Iraqi oil fields (East Baghdad) is located at a depth from 3044.3 to 3444 m. It is considered as one of the most problematic formations through drilling wells in East Baghdad. Most problems of Zubair shale are swelling, sloughing, caving, cementing problem and casing landing problem caused by the interaction of drilling fluid with the formation. An attempt to solve the cause of these problems has been adapted in this paper by enhancing the shale stability through adding additives to the drilling fluid. The study includes experiments by using two types of drilling fluids, API and polymer type, with five types of additives (KCl, NaCl, CaCl2, Na2SiO3 and Flodrill PAM 1040) in different concentrations (0.5, 1, 5 and 10) wt% and different immersion period (1, 24 and 72 h) hours. The effect of drilling fluids and additive salts on shale has been studied by using different techniques: (XRD, XRF, reflected and transmitted microscope) as well shale recovery. The results show that adding 10 wt% of Na2SiO3 to API drilling fluid results in a high percentage of shale recovery (78.22%), while the maximum shale recovery was (80.57%) in polymer drilling fluid type gained by adding 10 wt% of Na2SiO3.

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