Shale Swelling Research Articles

Impact of de-ionized water on changes in porosity and permeability of shales mineralogy due to clay-swelling

Hydraulic fracturing is widely applied for economical gas production from shale reservoirs. Still, the swelling of the clay micro/nano pores due to retained fluid from hydraulic fracturing causes a gradual reduction of gas production. Four different gas-bearing shale samples with different mineralogical characteristics were investigated to study the expected shale swelling and reduction in gas permeability due to hydraulic fracturing. To simulate shale softening, these shale samples were immersed in deionized (DI) water heated to 100 °C temperature and subjected to 8 MPa pressure in a laboratory reactor for 72 hours to simulate shale softening. The low-temperature nitrogen adsorption and density measurements were performed on the original and treated shale to determine the changes in micro and nano pore structure. The micro and nano pore structures changed, and the porosity decreased after shale treatment. The porosity decreased by 4% for clayey shale, while for well-cemented shale the porosity only decreased by 0.52%. The findings showed that the initial mineralogical composition of shale plays a significant role in the change of micro and nano pores and the pore structure alteration due to retained fluid from hydraulic fracturing. A pore network model is used to simulate the permeability of shale used in this study. To define pore structure properties, specific factors such as porosity, pore size, pore throat distribution, and coordination number were used. Furthermore, the anisotropy characteristics of shale were integrated into the model via a coordination number ratio. Finally, the change in permeability due to shale softening was determined and compared with untreated with the progress of shale softening. The simulation showed that the permeability of Longmaxi shale could decrease from 3.82E–16 m2 to 4.71E–17 m2 after treatment.

Preparation, performance and mechanism of 3-aminopropyltriethoxysilane modified graphene oxide as nano shale swelling inhibitor

Wellbore instability is a challenging technical problem in drilling operation, shale inhibitor can effectively inhibit shale hydration and dispersion, so as to stabilize the wellbore of shale. In this paper, graphene oxide was prepared by Hummer’s method, and modified by 3-aminopropyltriethoxysilane. The structure of modified graphene oxide was characterized using FT-IR and TGA, and the results showed that modified graphene oxide has been successfully prepared. The inhibitive performance was investigated by the linear swelling and hot-rolling tests, which shows the swelling rate of artificial core is reduced by 10.32% in 2.0% inhibitor solutions and the shale rolling recovery rate was reached 90.13% in 3.0% inhibitor solutions at the rolling condition of 120 °C × 16 h. Finally, the inhibition mechanism was studied, inhibitor can enter into the interlayer of shale and change the appearance of bentonite by physical and chemical interaction, and in that way achieve a good inhibition result.

On the stability of shale: the role of zeta potential (ζ) and Debye Hückel length (κ−1) on shale swelling

This work utilized electrochemical potential, linear swelling and water and ions uptake tests to correlate zeta potential (ζ) measurements with swelling results when different shales interacted with NaCl, KCl and CaCl2 solutions of different concentrations (water activities). Experimental results show that shale swelling and shrinkage seems to correlate well with changes in zeta potential and Debye Hückel length (κ −1) of shale’s charged surface. I believe that reduction of zeta potential and κ −1 leads to shale shrinkage while increase in zeta potential and κ −1 translates into shale swelling. Results also show that zeta potential and κ −1 of Pierre and Arco shale depends strongly on water activity (concentration) difference between shale and aqueous solutions. It was found that the formation and break up of an ionic shield cloud determines swelling and shrinkage of shale depending on the direction of water and ions transport. Results also suggest that, for constant temperature and medium viscosity (ƞ), the term (z/r) determines the effectiveness of ions to screen particle surface charge and it represents two opposing forces (electrostatic force and viscous force). The (z/r) for NaCl equals 0.28 m−1 which is lower than that of CaCl2 (z/r = 0.46 m−1 ) and KCl (z/r = 0.303 m−1 ).

Defining the optimum sequence in addition of shale inhibitor agents in WBDF considering inhibition of swelling of cuttings

• We proposed and optimized sequence addition of shale inhibitive agents to WBDF. • Inhibitive behavior of WBDF classified to low, med and high, based on performance. • We have shown shale inhibitor agents should be added before rheological additives • Asphasol and polyglycol better to be added as late additives in low temperature WBDF. • PHPA, bentonite should be added before KCl, PAC and XC polymer in mud preparation. Shale swelling inhibition property in water-based drilling fluid (WBDF) is an important issue in drilling fluid engineering. Against the importance of chemical compounds used to give this property to the drilling fluid, sequence of adding those additives is also much of concern. In the presented study, we propose an optimized sequence of additives in the formulation of a standard WBDF. In the formulation, potassium chloride (KCl), partially hydrolyzed polyacrylamide polymer (PHPA), and polyglycol are used as major shale inhibitors. Therefor, 23 drilling fluid samples with variation in sequences of adding additives were experimented. Then 16 different WBDF samples were produced through changing the position of KCl, PHPA, bentonite and polyglycol and more 6 drilling fluids were prepared by simultaneous change in the position of PHPA, bentonite and KCl. Also, one oil-based drilling fluid (OBDF) was also produced and experimented against shale inhibition for performance comparison. Analyzing of swelling curves of all these drilling fluids revealed three different behaviors of them in shale inhibition. Then after, the optimized sequence of adding the shale inhibitors was defined according to the best observed performance of all experimented fluids. It should be noted that the presented study only focuses on the inhibition of swelling of cuttings and not on the dispersion of cuttings.

An investigation of the effects of synthesized zinc oxide nanoparticles on the properties of water-based drilling fluid

The deterioration of drilling fluid properties during deep drilling causes problems like inefficient cutting removal, fluid invasion, and shale swelling, which increases non-productive time (NPT) and cost. Recently nanoparticles (NPs) based drilling fluid are introduced to address these impediments since these particles prove their advantages in different stages of petroleum exploration and recovery. Previous developments are concerned with the use of commercial zinc oxide (ZnO) NPs in inorganic KCl salt-based drilling fluid, although application of KCl in drilling fluid arouses environmental complications. In this study, ZnO NPs prepared in the laboratory are used in water-based drilling fluid (WBDF) to assess the effect of nanoparticles on the properties of drilling fluid at two temperature conditions of 40 °C and 80 °C. A base mud is formulated, and ZnO NPs with five different concentrations of 0.05, 0.1, 0.5, 1.0, and 2.0 wt% are mixed with the base mud. The experimental analysis shows that NPs improve the rheological properties of WBDF. When the concentration of NPs was 0.1 wt%, the yield point increased by 61.54% at 40 °C, and when the concentration of NPs was 0.05 wt%, the yield point increased by 60% at 80 °C. Besides, when the concentration of NPs is 0.05 wt%, 10-sec gel strengths are enhanced by 25% and 50% at 40 °C and 80 °C, respectively. The API low-pressure low-temperature (LPLT) filter volume is not significantly affected by the addition of NPs in WBDF. However, mud cake thickness continuously reduces with the increase of NPs concentrations. This result reveals that a superior rheological improvement is achieved at low NPs concentration (0.05 wt%) at higher temperature.

A novel technique for the modeling of shale swelling behavior in water-based drilling fluids

One of the most significant problems in oil and gas sector is the swelling of shale when it comes in contact with water. The migration of hydrogen ions (H+) from the water-based drilling fluid into the platelets of shale formation causes it to swell, which eventually increases the size of the shale sample and makes it structure weak. This contact results in the wellbore instability problem that ultimately reduces the integrity of a wellbore. In this study, the swelling of a shale formation was modeled using the potential of first order kinetic equation. Later, to minimize its shortcoming, a new proposed model was formulated. The new model is based on developing a third degree polynomial equation that is used to model the swelling percentages obtained through linear dynamic swell meter experiment performed on a shale formation when it comes in contact with a drilling fluid. These percentages indicate the hourly change in sample size during the contact. The variables of polynomial equation are dependent on the time of contact between the mud and the shale sample, temperature of the environment, clay content in shale and experimental swelling percentages. Furthermore, the equation also comprises of adjustable parameters that are fine-tuned in such a way that the polynomial function is best fitted to the experimental datasets. The MAE (mean absolute error) of the present model, namely Scaling swelling equation was found to be 2.75%, and the results indicate that the Scaling Swelling equation has the better performance than the first order kinetics in terms of swelling predication. Moreover, the proposed model equation is also helpful in predicting the swelling onset time when the mud and shale comes in direct contact with each other. In both the cases, the percentage deviation in predicting the swelling initiation time is close to 10%. This information will be extremely helpful in forecasting the swelling tendency of shale sample in a particular mud. Also, it helps in validating the experimental results obtained from linear dynamic swell meter.

Measurement of Deformation Heterogeneity During Shale Swelling Using Digital Image Correlation

AbstractRock-fluid interactions in shale formations are one of the main sources of wellbore instability issues and inadequate stimulation performance. For better planning of fracturing operations and optimizing production from these reservoirs, it is important to understand the mechanisms behind these interactions. These issues are especially prevalent in clay-rich shales, such as Tuscaloosa Marine Shale, which is the subject of this study. Conventional techniques to quantify these shale-fluid interactions comprise of measuring swelling in powdered rock grains or measurement of deformation in the whole pieces of the core using a linear variable differential transformer and strain gages. However, the contribution from individual laminae to overall deformation cannot be evaluated using these methods. In this study, we developed an experimental setup to evaluate the spatial deformation in shale during interaction with water using digital image correlation (DIC). Deformation of two shale samples, with 34 wt% to 51 wt% clay content, was studied. White paint was used to generate a random speckle pattern on the specimen and then immersed in deionized water. The deformation process was captured using a digital camera and images were analyzed using DIC to quantify the deformation. The implementation of the DIC technique enables the visualization and quantification of spatial deformation in the specimen during interacting with water. The results show the localization of large strains in select laminations. The results provide a better understanding of shale deformation when interacting with water in comparison to traditional measurements that can provide only an average strain value.

Experimental Evaluation on the Conductivity of Branch Fracture with Low Sand Laying Concentration and Its Influencing Factors in Shale Oil Reservoirs

Abstract The productivity of shale oil reservoirs is mainly determined by the hydraulic fractured reservoir volume. The branch fractures with low sand laying concentration are the main channels connecting the shale matrix and the main fractures. Maintaining the branch fracture conductivity is significant to the production of shale oil. In this study, a series of shale branch fracture conductivity and soaking experiments were conducted using a core flooding device and a small reactor, and the influences of different factors on the fracture conductivity were evaluated. The results show that when the sand laying concentration in fractures is less than 3 kg/m2, the branch fractures present a significant stress sensitivity. Particularly when the sand laying concentration is less than 1 kg/m2, and the closure pressure is greater than 15 MPa, there will be a risk of proppant embedded and fracture closed. The antiswelling agent has an inhibitory effect on the shale swelling. When the concentration of the antiswelling agent in the gel-breaking fluid is 2%, the swelling factor of shale powder is only 1.84%. Comparatively, the 0.5% of the antiswelling agent has a poor effect which can cause the shale rock to crack when the effective stress decreases. It can cause the fracture conductivity to decline by 70-90% when the gel-breaking fluid flows back associated with the shale oil. The probability of core breaking and proppant embedding will increase. The frequent shut-in and rapid open-flow for production can accelerate the damage of fracture conductivity. It is necessary to optimize the fracturing fluid and the open flow scheme to prevent the rapid decline of production in shale oil reservoirs.

Preparation and Evaluation of Ammonium-Succinic Salts as Shale Swelling Inhibitor and Its Application in Water-Based Drilling Fluids

Preparation and Evaluation of Ammonium-Succinic Salts as Shale Swelling Inhibitor and Its Application in Water-Based Drilling Fluids

Clay-water interaction inhibition using amine and glycol-based deep eutectic solvents for efficient drilling of shale formations

Water-based muds (WBMs) are preferred over oil-based muds owing to their lower cost and environmentally friendly nature. However, shale instability arising from clay-water interaction is a challenging concern. The current work explores the potential of deep eutectic solvents (DESs) as shale stabilizers for WBMs. Four amine and glycol-based DESs with different chemical composition were synthesized in the laboratory. The rheological and filtration properties of WBMs showed that DES-A, which is composed of tetrabutyl ammonium bromide and diethanol amine, and DES-B, which is composed of tetrabutyl ammonium bromide and diethylene glycol, with less sterically hindered cationic functionality improved the mud functionality. Shale inhibition performance of DESs was collected from capillary suction timer, linear swell meter and shale disintegration tests. These tests revealed that DES-A and DES-B are highly efficient and outperform the conventional shale inhibitor KCl and the commercially available ionic liquid 1-butyl-3-methylimidazolium chloride (BMIM[Cl]). Shale swelling in presence of 0.2 w/v% DES-A and DES-B decreased by ~54.6% and ~70.9%, respectively. Moreover, shale recovery improved by ~17.2% and ~18.2% and capillary suction time decreased by 45% and 48% in presence of 0.5 w/v% of DES-A and DES-B, respectively. The quaternary ammonium functionality helped in shale stabilization which was further improved due to the presence of –OH group in the hydrogen bond donor in DESs. Quick cost analysis showed the feasibility of industry scale application of DES-A and DES-B as shale inhibitors into WBMs.

Preparation of Ammonium Oleic Acid Salts and Their Evaluation as Shale Swelling Inhibitors in Water-Based Drilling Fluid

Abstract In this paper, ammonium oleic acid salts (AOS) were prepared from oleic acid and amines and investigated as low molecular weight shale swelling inhibitors. First, the inhibitory effect of AOS was investigated using the linear expansion test of bentonite. The results show that the inhibitor prepared from oleic acid and tetraethylene pentamine with a molar ratio of 1:2 (AOS-8) has an excellent inhibitory effect on the hydration expansion of bentonite. The inhibitory effect of AOS-8 on bentonite was further investigated in subsequent work steps using various methods, including the linear swelling test of clay and particle distribution measurement. The results show that AOS-8 has superior performance in inhibiting hydration swelling and dispersion of bentonite. With 0.5% AOS-8, the swelling rate was reduced to 37.7%, and the particle size of bentonite in water could be controlled with AOS-8. Finally, the inhibition mechanism of AOS-8 was determined in detail by scanning electron microscopy (SEM) and thermogravimetric analysis (TGA). In water-based drilling fluid, AOS-8 is compatible with conventional additives. It can also significantly improve the lubricating capacity of the mud cake after ageing at 120°C.

Application of Hybrid Silicate as a Film-Forming Agent in High-Temperature Water-Based Drilling Fluids.

Effective control of shale swelling and lost circulation using drilling fluid is considered the dominant strategy for maintaining borehole stability, especially drilling operations in deep oil and gas wells. In this work, a hybrid silicate that contains lithium silicate and potassium methyl silicate (PMS) was employed as a film-forming additive to reduce shale hydration and filtration loss in the high-temperature drilling fluid. Scanning electron microscopy (SEM) results revealed that a dense quartz crystal film coating on the shale can be formed in a hybrid silicate solution when the temperature exceeds 150 °C. The in situ-formed film on the shale surface with a thickness of 60–130 μm was composed of fibrous crystalline silica. Furthermore, the aqueous hybrid silicate exhibited enhanced hydration inhibition ability by preventing water invasion of the formation. Aqueous hybrid silicate with a concentration of 0.5–3 wt % lithium silicate and 0.1–0.2 mol/L PMS was first chosen to obtain the optimum concentration according to the hydration inhibition ability and film formation characteristics. The hybrid silicate was added into a drilling fluid formulation applicable in high-pressure and high-temperature conditions, and the rheological characteristics and filtration properties were investigated. The results confirmed that drilling fluids with the addition of hybrid silicate can mitigate variation of viscosity and yield point before and after aging at 180 and 220 °C. Besides, the filtration behavior was also improved by adding hybrid silicate into the drilling fluid. A lower filtration loss was observed at the concentration of 1.0 wt % lithium silicate and 0.2 mol/L potassium methyl silicate, which showed 63 and 50% HPHT fluid loss reduction for unweighted and weighted formulations at 205 °C and 3.5 MPa, respectively. In addition, the drilling fluid featured stable rheological and filtration properties and excellent shale hydration inhibition characteristics when exposed to high temperatures, making it a promising candidate for drilling in deep oil and gas wells.

Insight on the inhibitive property of potassium ion on the stability of shale: a diffuse double-layer thickness (\u03ba\u22121) perspective

It is believed that potassium ions reduce the hydration energy and swelling of clays and thus promoting stability to shales. This belief was made based on volumetric and linear expansion data obtained from shale and KCl solutions interactions. However, swelling data alone is not adequate to mitigate wellbore instability in shale. Such data must be incorporated with mechanical and physicochemical data for complete and accurate wellbore instability analysis.This paper presents clear experimental evidence showing that concentrated potassium chloride solutions tend to suppress shale swelling as higher concentration of potassium ions collapses the diffuse double layer of clay particles causing shale shrinkage which confirms the notion that the Debye length (κ−1) decreases as the ionic concentration increases.Results show that there exists a KCl concentration threshold above which shale’s compressive strength deteriorates significantly. This concentration threshold was found to hover around 5% by weight. The amount of water and ions uptake into shale was quantified using gravimetric measurements. Significant potassium ions invasion into shale was experimentally measured as KCl solution concentration increased which proved the leaky nature of shale’s membrane. The reduction of shale’s compressive strength seems to be well correlated with the amount of ions uptake into shale. Moreover, data suggests that shale’s compressive strength was not significantly impacted by swelling. It was possible to gravimetrically separate osmotic water from associated water as shale interacted with KCl solutions. Results suggest that osmotic water is responsible for shale swelling since it is unattached to ions which makes it free to move around inside shale. On the other hand, data suggest that associated water does not contribute to shale swelling as it is bound to potassium ions which makes it unfree to move around. It is fair to state, based on our experimental data, that osmotic water is responsible for shale swelling while associated water contributes to shale’s compressive strength alteration.

Potassium carbonate based deep eutectic solvent (DES) as a potential drilling fluid additive in deep water drilling applications

Drilling fluid design is the most vital step in drilling phase. An ideal drilling fluid apart from exhibiting good thixotropic behavior should be efficient in inhibiting the hydrates formation, suppressing shale swelling and improving mud rheology. Lately, Ionic Liquids are being used as drilling fluid additives to increase the efficiency of drilling mud. Recent research has given evidences that imidazolium based Ionic liquids are toxic, not biodegradable and their preparation require sophisticated techniques and equipment. Deep Eutectic Solvents (DES) are regarded as fourth generation ionic liquids and are claimed to be the greener and cheaper alternative of traditional ionic liquids. This research utilizes potassium carbonate based DES to check its candidacy as a potential drilling fluid additive. DES based drilling mud showed optimum performance at 0.5% conc. (of DES) by delaying induction time of hydrates formation by 33.8% and decreasing mud cake thickness and filtrate volume by 36% and 24% respectively. Moreover, from a “free style” experiment DES proved to be an excellent shale inhibitor by inhibiting shale swelling upto 84%.The inhibiting traits of DES are mainly attributed to its hydrogen bond formation capability with hydrates and clay.

The influence of shale swelling on casing deformation during hydraulic fracturing

Casing deformations during hydraulic fracturing are a serious problem in the Weirong shale gas field. This study focuses on the mechanism of shale swelling-induced casing deformation. First, the characteristics of the casing deformations in the Weirong shale gas field were analyzed. Subsequently, the mechanism of shale swelling during immersion was investigated and numerical simulations were performed to investigate the effect of shale swelling on casing deformation. Finally, we discussed various countermeasures to suppress casing deformation. The results demonstrate that clay-swelling during immersion leads to the propagation and expansion of fractures along the beddings, thereby causing shale swelling. Furthermore, the casing stress increases with the increase in shale swelling. The swelling formation distributions have a significant effect on the type of casing deformation. Symmetric swelling formation distributions cause extrusion deformation, and asymmetric swelling formation distributions cause bending deformation, which is similar to the type of casing deformation observed in the WY 23–5 well in the Weirong shale gas field. Furthermore, shear deformation can also be induced if the dip angle of the swelling formation is less than 90°. Increasing the casing thickness and steel grade, and adjusting the Poisson's ratio of the cement sheath does not have a significant effect on suppressing shale swelling-induced casing deformation. The effect of cement quality on casing deformation depends on whether the cement void can provide a sufficient area for stress release. Perforations provide artificial stress release areas and reduce the casing stress, in spite of local stress concentration near the perforation points. The findings obtained herein provide a new understanding of the casing deformations in the Weirong shale gas field, and provide practical solutions to suppress casing deformation. • Casing deformation characteristics of shale wells in Weirong shale gas field were analyzed. • The mechanism of shale swelling-induced casing deformation was investigated. • Casing stress increases with the increase in shale swelling. • Swelling formation distribution affects the type of casing deformation. • Countermeasures to suppress the casing deformation were discussed.

Reservoir Wellbore Stability Analysis and Weak Zones Identification Using the 1D MEM, Swelling Tests and UCS: A Case Study From Mumbai Offshore, India

Reservoir geomechanical studies play a decisive role in identifying wellbore instability and weak zones in offshore petroleum reservoirs. In this study, an integrated workflow developed with 1D Mechanical Earth Models (1D MEM), uniaxial compressive strength and swelling tests using well logs, drilling, and core data of production and exploratory wells from the North-Heera field, Mumbai offshore, India. Lithology-based correlations are utilized for calculating continuous profiles of rock mechanical properties by taking well logs as a primary source of input. Insights of fracture gradients and stresses are generated by interpretation of the pore pressure. UCS created from the well logs shows the low value of 15 MPa and high Poison's ratio of 0.38–0.45. Fracture pressure analysis of the wells specifies the lower fracture initiation pressures at 300 m are 5ppg–15ppg, which are shale and clay formation. Shale swelling tests are performed to know the hydration properties of shales present at shallow depths. The core samples' loading tests' results are very close to the UCS models constructed from the well logs. The combined analysis examines fracture pressures around wellbores, hydration of shales, weak zones identification, and wellbore instability.

Evaluation of Low Salinity Water Injection Improved Oil Recovery in Liquid-Rich Unconventional Reservoirs

Since the shale matrix has a very low permeability, the flow in the matrix is often transient flow. Hence, conventional reservoir simulators often do not accurately estimate the mass exchange between matrix and fractures. To evaluate the effect of water injection on oil recovery realistically, reservoir simulators need to incorporate the mass transport in the reservoir at different scales. These issues have motivated us to evaluate the contribution of water injection on oil recovery in liquid-rich unconventional reservoirs accounting the effects of salinity, fluid type, shale swelling, and wettability alteration. In this research, a new mass transport model is used to compute the mass transfer mass exchange between the rock matrix and the fractures. A geomechanical model is also used to account for the effect of fluid–rock interaction on the permeability and porosity. The coupled model is solved for every matrix block within the reservoir-scale model to evaluate the overall effect of salt concentration, shale swelling, and wettability alteration on the mass exchange between the fractures and the shale matrix. The reservoir-scale simulation helps to determine the phase pressure, saturation, solute concentration, and liquid production. A computer code was developed to solve the transport and geomechanical equations simultaneously, and the code is validated with the benchmark problems as shown in the Appendix. The results show that osmosis significantly contributes to the recovery of oil from very low permeability shale matrix over a long time period. Shale matrix swelling also significantly reduces the permeability of the shale matrix and fractures, reducing overall oil recovery. Therefore, water injection is not recommended for formations with swelling potential. The modified-zipper pattern is recommended for enhanced oil recovery operations. The simulation results also suggested that oil recovery can be improved by increasing the density of hydraulic fractures.

Synergistic effect of polymer and nanoparticles on shale hydration and swelling performance of drilling fluids

The inhibition attributes of drilling formulations typically rely on the type of additives, concentration, and reactivity with shale formations. In this work, the impact of ZnO and polymer on rheological, shale inhibition, and filtration properties were studied. Several drilling formulations were prepared with different concentrations of ZnO and polymer in the deionized water. Rheological properties (viscosity, yield stress, and gel strengths) were measured using a hybrid rheometer to investigate drilling formulation performance. The filtration properties drilling formulations and permeability analysis of filter cake was performed to analyze the impact of ZnO and associative polymer on fluid loss. SEM-EDS analysis of filter cake was accomplished to investigate the dispersion of drilling additives on filter cake. Shale swelling inhibition characteristics of drilling formulations were determined by performing shale dispersion test and linear swelling test as per API standards. The shale dispersion test showed 97% shale recovery with BPN4 formulation compared to 81% of shale recovery with the base formulation. Shale swelling rate decreased to 6.69% with BPN4 formulation compared to the 14.29% of shale swelling rate in the base formulation. Shale inhibition results showed that the synergic impact of ZnO and polymer in the formulations enhanced the inhibition characteristics. Contact angle measurements showed that synergy of ZnO and polymer in the drilling formulation increased the hydrophobicity of the shale surface. Hence, drilling formulations comprising both ZnO and polymer can be applied to drilling operations for superior inhibition characteristics.

A critical parametric review of polymers as shale inhibitors in water-based drilling fluids

Wellbore stability is essential to be maintained during drilling operation. It is on target due to many issues among them shale hydration is most critical problem using water-based drilling fluids especially. The reactive clay minerals of shale have greater affinity towards water and show swelling when interact with water and make wellbore conditions unstable. Different inhibitors have been utilized to inhibit water invasion. Among them, polymers proved to be efficient and biodegradable. In this paper, responsible clay minerals for hydration and their reactivity towards water is explained. The parametric mechanism of hydration and inhibition are thoroughly reviewed. In this review paper, the inhibition performance parameters of polymers are presented. Polymers utilized in WBDF are critically reviewed with respect to their inhibition ability based on the performance parameters like electrostatic interaction, hydrogen bonding with clay minerals, thermal stability, and their effect on drilling fluid rheology. Different researchers have explained some of the parameters. But they are found to be insufficient to explain all the important parameters. There are other parameters to investigate the polymer's performance that are required to be explained for an efficient inhibition. These parameters are electronegativity difference in the active site of polymer, hydrophobicity, concentration, and agglomeration. These parameters are also important to discuss because they affect polymer's performance and drilling fluid's rheological properties. Nanoparticles have been used for inhibition with polymers and their effectiveness to plug nanopores is also reviewed. Some of the polymers were found to be unstable and contaminating nanoparticles. The reason behind this problem have also been explained parametrically here. The limitations of utilized polymers have been discussed in this paper w.r.t. performance parameters. Polymer performance and characterization results are presented and evaluated w.r.t. to performance parameters. Future perspective for a better inhibition performance is the utilization of a polymer with improved performance parameters. • Shale swelling cause wellbore instability problems using water-based drilling fluids. • Polymers proved to be efficient inhibitors during drilling operation with some limitations. • Performance parameters have been explained to investigate polymer's performance. • Polymers separately and with nanoparticles are reviewed based on different performance parameters.

Swelling of Shales with Slickwater in Carbon Dioxide

Usage of shale gas as an energy source offers additional reassurance if fossil fuels become depleted. Because the shale reservoir is buried deep, the formation has the characteristic of high ground...