Wellbore Stability In Shale Formations Research Articles

Core-shell structured polystyrene microspheres for improving plugging performance of oil-based drilling fluids

To avoid damage to wellbore stability in shale formations from drilling fluid intrusion and pressure transmission, it is important to develop a plugging material that can effectively plug micropores and fractures in shale formations. In this paper, polystyrene microspheres (CPM) with core-shell structure were synthesized by seed emulsion polymerization, and characterized by infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), particle size analysis, TEM observation and contact angle test. The effects of CPM on emulsion stability and emulsion rheological performance were evaluated by electrical stability tests and rheological performance tests, respectively. The plugging performance was evaluated using filter materials with different pore sizes as filter media. The experimental results showed that CPM had good thermal stability with a thermal decomposition temperature up to 374.3 °C. CPM had a core-shell structure with a median value (D50) of 229 nm and a three-phase contact angle of 116.2°. The synergistic effect of CPM and organoclay can significantly improve the stability of emulsions and viscosity at low shear rates. For different pore sizes of filter media, CPM achieved effective plugging of micropores, reducing fluid loss volume to less than 6 mL for different pore sizes of micropore filter membranes and 29.6% for ceramic sand discs. In this paper, a preparation method of plugging material with good plugging performance was given, which provided technical support for the development of plugging agents for Oil-based drilling fluids (OBDFs).

The thermoporoelastic coupling analysis of wellbore stability in shale formation under supercritical CO2 drilling conditions

Supercritical carbon dioxide (ScCO2) drilling can effectively protect shale formation from hydration damage and improve drilling rate comparing to conventional drilling technology. The wellbore stability of shale formation is one considerable issue under ScCO2 drilling conditions. In this study, the numerical simulations are performed to calculate collapse cycling time of shale formation under ScCO2 drilling conditions based on thermoporoelastic coupling model. The results show that comparing to water seepage condition, the variation of formation temperature is larger, pore pressure and stress are lower for ScCO2 seepage condition without adsorption effect, the comparison between water and ScCO2 seepage conditions verifies the thermoporoelastic coupling model. For ScCO2 drilling conditions, if adsorption‒induced strain is ignored, the risk of wellbore collapse will be slightly underestimated comparing to the results with adsorption effect. When adsorption‒enhanced elastic modulus is ignored, the risk of wellbore collapse will be significantly underestimated comparing to the results with adsorption effect. The wellbore collapse may occur with the increasing well depth for ScCO2 drilling conditions. This study can provide the theoretical guidance for exploiting shale reservoirs using ScCO2.

Effects of Multi-Wall Carbon Nanotubes (MWCNT) on Performance of Water Based Mud (WBM)

The present review article expresses the effectiveness of different types of Multi-Wall Carbon Nanotube(s) (MWCNT) on the rheological properties of Water-Based Mud drilling fluid. Shale formations are troublesome according to their water sensitivity characteristic, low Nano-Darcy permeability with small nanometer-sized pore throats that are not effectively sealed by the solids in conventional drilling fluids. Water invasion into the shale formations causes different problems in the drilling industry. Nanoparticle additives have the potential to be used in drilling operations due to their large surface area and lower kinetic energy than micro-additives. The test results demonstrate that multi-wall carbon nanotube improves the rheological properties of the WaterBased Mud drilling fluid. Acidic-surface modified carbon nanotube in the presence of Polyethylene Glycol (PEG) increases the plastic viscosity and yield point of the sample more than unmodified carbon nanotube and hybrid multiwall carbon nanotube. Test results show that multi-wall carbon nanotubes (MWCNT) improve shale stability and shale recovery, finally leading to more well-bore stability in shale formations.

Influence of relation between stress field and bedding space on wellbore stability in shale formation

The shale gas reservoir in Jiaoshiba area is well developed with bedding and shows strong anisotropy, which leads to the problems of wellbore instability in the drilling process. At present, for the shale rich in bedding, the conventional calculation model of shale wellbore collapse pressure cannot meet the needs of shale wellbore stability analysis. In this paper, the analytical method considering the influence of bedding is more accurate. Therefore, in this paper direct shear tests and tri-axial mechanic experiments were conducted on the down-hole core rocks of LongMaxi reservoir shale formation, and the obtained experimental results were combined with single discontinuity theory to establish the characterization method of shale strength anisotropy. Then, combining the characterization method of shale strength anisotropy with the sidewall stress distribution model, the calculation method of borehole collapse pressure is established. Finally, the JY1HF well is taken as an example for calculation and comparative analysis. The results show that the LongMaxi reservoir shale strength deteriorating after drilling fluid immersion is not the main control factor of borehole instability; the shear slip along the weak bedding plane is the main mechanical mechanism of borehole instability. The collapse pressure calculated by the conventional model decreases with the increase of the well inclination, and the collapse pressure calculated by the model in this paper shows a trend of increasing first and then decreasing with the increase of the well inclination, and the results calculated by the model in this paper are in good agreement with the actual working conditions. The research results of this paper can provide theoretical basis and reference for drilling design and borehole trajectory optimization of shale gas wells in Jiaoshiba area or other areas.

Synthesis of a Biodegradable and Environmentally Friendly Shale Inhibitor Based on Chitosan-Grafted l-Arginine for Wellbore Stability and the Mechanism Study.

We synthesized a biodegradable and environmentally friendly shale inhibitor based on chitosan-grafted l-arginine (CA) for wellbore stability in shale formation. The structure of CA was characterized by Fourier-transform infrared spectroscopy. Linear swelling, shale hot-rolling recovery, shale inhibition durability, and sedimentation experiments were used to evaluate the inhibition properties of CA and compared with the commonly used inhibitors potassium chloride (KCl) and polyamines (HPA and SIAT). The results showed that the inhibition of CA was better than that of KCl, HPA, and SIAT and that it can have a shale hot-rolling recovery of more than 90% at 150 °C, which indicated that CA had higher temperature resistance and longer durability. More importantly, it can be biodegraded as exhibited by the biodegradibility experiment. The inhibition mechanism of CA was studied by particle size distribution, X-ray diffraction, scanning electron microscopy, zeta potential analysis, and contact angle test. The strong inhibition of CA can be attributed to its encapsulation of MMT and shale surfaces. The CA with strongly positively charge was firmly adsorbed on the surface of MMT and shale, which not only neutralized the negative charge of MMT, compressed the diffused electric double layer, but also increased the contact angle of MMT and shale surface which enhancing hydrophobicity of MMT and shale. The hydration swelling and dispersion of MMT and shale were further inhibited. In addition, compatibility experiments showed that CA was compatible with commonly used treatment agents. CA did not affect the rheology of water-based drilling fluids and can reduce fluid loss after aging.

Mechanistic study of improvement of wellbore stability in shale formations using a natural inhibitor

Wellbore instability is a big challenge in shale formations. The objective of this study is to investigate the effectiveness of a natural additive as a shale inhibitor. The capability of this additive for reducing ion movement into shale and plugging its pore throats has been tested and compared with salts and nano particles. The ions and water movement into shale and resultant swelling was measured by modified gravimetric, swelling and modified immersion tests. The results showed that using Henna extract could reduce the ion and water movement into shale. In addition, the results of pore pressure tests showed that 3 wt % of Henna extract are more effective than nano particles and could completely plug the pore throats of shale while the mud rheological properties are still maintained. The findings of this study show that the Henna extract could be considered as a cost-effective and an environmentally-friendly shale inhibitor.

Analysis of influencing factors of wellbore stability in shale formations

In the process of drilling, wellbore instability in shale formations is frequent and makes it hard to drill. In order to find causes of wellbore instability in shale formations, this paper proposed a wellbore instability analysis model to reveal the combined effects of anisotropic strength of shale, occurrence of stratification, strength reduction, and seepage stresses caused by drilling fluid on wellbore instability. The results show that when the occurrence of bedding planes is certain, it can maintain wellbore stability in the condition of lower mud weight to choose a reasonable azimuthal angle. With changes of shale strength and porous flow, the wellbore would increase the level of instability with drilling time, which means mud weight needs to be increased to keep the wellbore from collapsing.

Wellbore stability model for horizontal wells in shale formations with multiple planes of weakness

Wellbore collapse is a common problem during drilling operations in the Longmaxi shale formation, which vastly restricts drilling efficiency and shale gas development. For a horizontal well in particular, the long period of drilling increases the possibility of collapse. The central reason for the frequent wellbore collapses in shale formations is that shale has abundant planes of weakness, that is, bedding planes and fracture planes. These weak planes reduce shale strength and increase the anisotropy of the shale, complicating the wellbore instability issue. Therefore, this paper extends results of previous work and presents an attempt to establish a new model to investigate the influence of multiple groups of weak planes on wellbore stability in shale formation. By using this model, the influences of weak planes on stress distribution and shale strength are analysed respectively. It is shown that the anisotropy of shale formation makes stress distribution variable. Besides, the presence of weak planes decreases shale strength and this reduction of strength becomes larger with the increasing number of groups of weak planes. In particular, with more than four groups of weak planes, shale strength is entirely controlled by the weak plane. Based on the analysis of shale strength and effective stress at the wall of borehole, the investigation on influence factors of wellbore stability in shale formation has been conducted. The results indicate that collapse pressure has increment with increasing anisotropy of shale formation. Additionally, different occurrence and number of weak planes cause variation in collapse pressure. For a horizontal well, the selection of appropriate drilling azimuths can reduce the effect of weak planes on the borehole. The interaction between drilling fluid and shale leads to incremental collapse pressure, and this increment is higher in the multiple groups of weak planes and strong anisotropy condition. Finally, this model was applied to a field case in the southern Sichuan Basin, China. The model was consistent with field experience, proving its practicability in drilling operations.

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

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.

Simulation of wellbore stability with thermo-hydro-chemo-mechanical coupling in troublesome formations: an example from Ahwaz oil field, SW Iran

Wellbore stability is a main concern in drilling op- eration. Troublesome drilling issues are chemically active for- mations and/or high-pressure-high-temperature environments. These are mainly responsible for most of wellbore instabilities. Wellbore failure is mostly controlled by the interaction between active shales and drilling fluid in shale formations. The factors influencing this interaction consist of fluid pressure, tempera- ture, composition of drilling fluid, and exposure time. In this paper, a non-linear fully coupled chemo-thermo-poroelasticity model is developed. At first, a fully implicit finite difference model is presented to analyze the problem, and then, it is verified through comparison with analytical models. For this purpose, a computer code has been written in MATLAB envi- ronment. Results indicate that chemical osmosis and thermal osmosis significantly influence the wellbore stability in shale formations. Cooling and high salinity in mud decrease pore pressure and total tangential and radial stresses in the formation and vice versa. Moreover, CaCl2 solutions result in higher osmotic pressure than NaCl solutions. The type of constitutive model is investigated on wellbore failure. In addition, the proposed model is applied for wellbore instability in Ahwaz oil field, SW Iran. Results show that the proposed model considerably predicts the wellbore instability in this field.

Wellbore Stability in Shale Formation Using Analytical and Numerical Simulation

Optimization of drilling fluid parameters such as mud weight, salt concentration, and temperature is essential to alleviate instability problems during drilling through shale sections. The selection of suitable mud parameters can benefit from analyses that consider significant instability processes involved in shale-drilling–fluid interactions. This paper describes the development of analytical and numerical method for describing shale deformation. Appropriate and optimum mud pressure in which the highest consistency happens is calculated with analytical and numerical methods. It was found that, the predicted mud pressures obtained from two methods are approximately equal. The stress condition is considered non-hydrostatic. From the analytical and extensive numerical simulation it was concluded that with applying any mud pressure the well shape changes from spherical to elliptical. As the selection of the optimum mud pressure is based on the less movement and maintaining the well shape constant.

Nanoparticle Use in Drilling Fluids Can Effectively Reduce Permeability in Shale

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157031, ’Application of Nanotechnology in Drilling Fluids,’ by Katherine Price Hoelscher, SPE, Guido De Stefano, SPE, Meghan Riley, SPE, and Steve Young, SPE, M-I SWACO, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed. The potential to apply water-based drilling fluids confidently in unconventional shale formations has been studied using engineered nanoparticles to minimize shale permeability by physically plugging the nanometer-sized pores. Nanoparticle technology and testing protocols were developed using the Marcellus and the Mancos as shale candidates. Nanoparticles in this study are specifically designed to plug the nanometer-sized shale pores physically, thereby reducing pressure transmission in the shale. Introduction Silica nanoparticles are commercially available and can be engineered to meet all specifications needed for the purpose. The particle size can vary between 5 and 100 nm. The right sizes of nanoparticles can be selected, and, in combination with a correct fluid-loss package, the particles can minimize the fluid/rock interaction. Surface treatment on the nanosilica particle has been discovered to have a major influence on the final performance. An investigation into using nanoparticles as a drilling-fluid additive to enhance wellbore stability has been successful. The nanomaterial works by virtually shutting off water movement between the formation and wellbore. In shale formations with nanodarcy permeability, such as the Marcellus, the usual drilling-fluid method of relying on a filter cake to reduce fluid loss (or leakoff) cannot be used because a filter cake may not form because of the extremely low permeability of the shale. The solution for this problem is to engineer a nanoparticle that will be added to the drilling fluid to plug the pores of the shale and shut off water loss. Background The hurdle to maintaining wellbore stability in shale formations is to control the water interaction with the rock. The water enters the shale through pores, which vary in size from approximately 3 to 100 nm, inducing fractures and, thereby, reducing the stability of the wellbore. By effectively plugging the exposed pores of the rock and not allowing water to enter, wellbore stability is retained. One conventional bridging theory is referred to as the one-third rule of filtration (Abrahm’s theory), where the material used to plug a pore is required to be approximately one-third to one-seventh of the size of median pore opening. There are other theories with varying size requirements for the plugging material; however, none is perfect. An ideal plugging material also will accommodate the variability in pores within the formation.

Maintaining the stability of deviated and horizontal wells: Effects of mechanical, chemical and thermal phenomena on well designs

Wellbore instability, particularly in shale formations, is regarded as a major challenge in drilling operations. Many factors, such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects, should be considered in well trajectory designs and drilling fluid formulations in order to mitigate wellbore instability-related problems. A comprehensive study of wellbore stability in shale formations that takes into account the three-dimensional earth stresses around the wellbore as well as chemical and thermal effects is presented in this work. The effects of borehole configuration (e.g. inclination and azimuth), rock properties (e.g. strength, Young's modulus, membrane efficiency and permeability), temperature and drilling fluid properties (e.g. mud density and chemical concentrations) on wellbore stability in shale formations have been investigated. Results from this study indicate that for low-permeability shales, chemical interactions between the shale and water-based fluids play an important role. Not only is the activity of the water important but the diffusion of ions is also a significant factor for saline fluids. The cooling of drilling fluids is found to be beneficial in preventing compressive failure. However, decreasing the mud temperature can be detrimental since it reduces the fracturing pressure of the formation, which can result in lost-circulation problems. The magnitude of thermal effects depends on shale properties, earth stresses and wellbore orientation and deviation. Conditions are identified when chemical and thermal effects play a significant role in determining the mud-weight window when designing drilling programmes for horizontal and deviated wells. The results presented in this paper will help in reducing the risks associated with wellbore instability and thereby lowering the overall non-productive times and drilling costs.

Predictions of wellbore stability in shale formations at great depth : Steiger, R P; Leung, P K Proc International Symposium on Rock at Great Depth, Pau, 28–31 August 1989V3, P1209–1218. Publ Rotterdam: A A Balkema, 1989

Predictions of wellbore stability in shale formations at great depth : Steiger, R P; Leung, P K Proc International Symposium on Rock at Great Depth, Pau, 28–31 August 1989V3, P1209–1218. Publ Rotterdam: A A Balkema, 1989