Wellbore Instability Problems Research Articles

Application of Nanosilica in Glycerol-Based Drilling Fluid for Shale Formations

SummaryIn this study, we perform several tests to develop a formula of glycerol-based drilling fluid that is suitable for shale formations with severe wellbore instability problems. Drilling fluids with varying combinations of nanosilica, glycerol, sodium carboxymethyl cellulose (Na-CMC), and xanthan gum (XG) in organic soil glycerol-based slurry are tested, and the effects of nanosilica on the swelling of shale samples and the lubricity of drilling fluids are also investigated to verify the feasibility of designed drilling fluids. The experimental investigations reveal that the values of apparent viscosity (AV), plastic viscosity (PV), and yield value (YP) of the optimal formulation meet the rheological parameters required for the drilling of shale formations. The AV and PV values of drilling fluid with 55:45 glycerol/water ratio are lower than those of drilling fluids with other glycerol/water ratios. A higher XG content means higher YP value in the experiment and 0.4% XG is suitable for the glycerol-based drilling fluid to prevent the collapse of the shale wellbore. There is a critical nanosilica content threshold (0.5%), and the filtration loss (FL) increases gradually when this threshold is exceeded due to the agglomeration of nanosilica. The nanosilica coated on clay particles in shales because of the formation of hydrogen bonds results in a decrease in permeability of shale formations. The swelling of shale through hydration is greatly reduced by 37% and the sticking coefficient of drilling fluid is reduced by 28% when 0.5% nanosilica is added. The addition of nanosilica to glycerol-based drilling fluid is significant to deal with the wellbore instability problems in troublesome shale formations.

Experimental Research of Shale Pellet Swelling in Nano-Based Drilling Muds

The drilling of clay-rich formations, such as shale, is an extremely demanding technical and technological process. Shale consists of mixed clay minerals in different ratios and in contact with water from drilling mud. It tends to swell and cause different wellbore instability problems. Usually, the petroleum industry uses various types of salt and/or polymers as shale hydration inhibitors. The aim of this research was to determine whether nanoparticles can be used as shale swelling inhibitors because due to their small size they can enter the shale nanopores, plug them and stop further penetration of mud filtrate into the shale formation. Swelling of bentonite-calcium carbonate pellets after 2 and 24 h in water and drilling mud (water, bentonite, PAC and NaOH) without nanoparticles and with addition of TiO2 (0.5, 1 and 1.5 wt%) and SiO2 (0.5, 1 and 1.5 wt%) nanoparticles was measured using a linear swell meter. Additionally, granulometric analyses of bentonite as well as the zeta potential of tested muds containing nanoparticles were performed. Based on the laboratory research, it can generally be concluded that the addition of SiO2 and TiO2 nanoparticles in water and base drilling mud reduces the swelling of pellets up to 40.06%.

On the use of an agro waste, Miscanthus x. Giganteus, as filtrate reducer for water-based drilling fluids

During drilling operations, the influx of liquids to the producing zones can cause wellbore instability problems and decrease the well’s productivity. Different additives are used as filtrate reducers in water-based drilling fluids (WBFs). The growing need of more sustainable drilling operations motivates the incorporation of residues and waste in WBFs formulations. This study reports the evaluation of Miscanthus x. Giganteous (MxG) fines as filtrate reducers in WBFs, promoting the valorization of this agro waste. MxG was characterized by FTIR, and the spectra exhibited characteristic bands of its major constituents. The MxG size reduction was performed by grinding and sieving it through #100, 200 and 325 mesh screens, and the particle size distribution was obtained by optical microscopy. TGA results showed that the sieved MxG grass fines exhibited thermal stability in the range for use in deep and ultra-deep wells, and the degradation profiles were dependent on the average particle size. The filtration properties of all WBFs studied were well described by Darcy’s law, allowing the determination of the spurt loss volume. The filtration performance of the WBFs was significantly improved when the average particle size of the MxG fines decreased, exhibiting comparable or superior results than other materials obtained by more complex, solvent-dependent, expensive and time-consuming processes described in literature.

Optimization of Deviated and Horizontal Wells Trajectories and Profiles in Rumaila Oilfield

Directional and horizontal wellbore profiles and optimization of trajectory to minimizeborehole problems are considered the most important part in well planning and design. Thisstudy introduces four types of directional and horizontal wells trajectory plans for Rumailaoilfield by selecting the suitable kick off point (KOP), build section, drop section andhorizontal profile. In addition to the optimized inclination and orientation which wasselected based on Rumaila oilfield geomechanics and wellbore stability analysis so that theoptimum trajectory could be drilled with minimum wellbore instability problems. The fourrecommended types of deviated wellbore trajectories include: Type I (also called Build andHold Trajectory or L shape) which target shallow to medium reservoirs with lowinclination (20o) and less than 500m step out, Type II (S shape) that can be used topenetrate far off reservoir vertically, Type III (also called Deep Kick off wells or J shape)these wells are similar to the L shape profile except the kickoff point is at a deeper depth,and design to reach far-off targets (>500m step out) with more than 30o inclination, andfinally Type IV (horizontal) that penetrates the reservoir horizontally at 90o. The study alsorecommended the suitable drilling mud density that can control wellbore failure for the fourtypes of wellbore trajectory.

Inclined Wellbore Stability in High Temperature Formations of Drilling

In recent years, exploring and developing oil and gas continuously expands into high-temperature environments, such as the Gulf of Mexico, North Sea, South China Sea, etc. Development of a high-temperature oil field from a platform always requires directional wells or extended reach wells (ERWs) departing from a central cluster to their targets at different depth of water in various azimuth. When drilling wells in high temperature formations, there is commonly associated with a suite of wellbore instability problems that are not normally encountered in onshore and normal temperature formations drilling. These problems are usually related to the presence of typically weak overburden sediments, unconsolidated formations, a small sedimentary coverage above the reservoir, and a great temperature difference between the drilling fluid and formation at the bottom hole In the past decades, a number of studies have been conducted to study the wellbore stability. However, few of the models are specific for wellbore stability of the inclined high temperature wellbores. In this work, an inclined wellbore stability model for high temperature formations is developed. The numerical method of the model is also provided. The study shows that drilling along the direction of minimum horizontal in-situ stress is safer than drilling in other directions, and the wellbore with a high inclination poses more risk of wellbore instability than the wellbore with a low inclination. It also shows that both of the wellbore collapse pressure gradients and wellbore fracture pressure gradients will increase as the temperature of borehole rises, and the fracture pressure is more sensitive to temperature. The model provides a practical tool to predict the stability of inclined wellbores for high temperature formations.

Influence of (3–Aminopropyl) triethoxysilane on entrapped polypropylene at nanosilica composite for shale swelling and hydration inhibition

The unforgiving shale formations require special shale inhibitors to mitigate wellbore instability problems. (3–Aminopropyl) triethoxysilane polypropylene-nanosilica composite (PNSC + NH2) was evaluated in water-based drilling muds (WBDMs) as a clay swelling and hydration inhibitor. The size distribution, functional groups, morphology, and thermal stability of the PNSC + NH2 were studied. Rheological and filtrate volume tests were carried out to determine the influence of the PNSC + NH2 on WBDMs. The clay swelling inhibition performance of the PNSC + NH2 mud system was examined and compared with that of potassium chloride (KCl) and KCl + partially hydrolyzed polyacrylamide (KCl + HPAM) through clay swelling inhibition test, extended clay swelling inhibition test (inhibition longevity test), and BET analysis test. Four shale specimens were prepared with compactor cell for the measurement of clay swelling using the Linear Swell Meter. Drilling muds were examined on 16 mm thick-compacted shale pellets using the highest concentration of smectite. A shale rolling recovery test was conducted to determine the shale hydration-retardation. Results showed that the PNSC + NH2 particle has good dispersibility, with a size distribution predominantly distributed between 80 and 390 nm. The inclusion of 1.5w/v% PNSC + NH2 concentration enhanced the plastic viscosity and yield point of WBDM from 11 to 15 mPa s and 9–14 Pa, respectively. Also, it reduced the API filtrate volume of the WBDM from 10.2 to 7.8 ml. The clay swelling inhibition performance of the WBDM for 36 h showed 62% swelling and was reduced to 42% by KCl, 33% by KCl + HPAM, and 28% by PNSC + NH2. When the inhibition test was extended to 60 h, the swelling increased to 44% for KCl, 40% for KCl + HPAM, and 29% for PNSC + NH2 mud systems. These results revealed that the PNSC + NH2 has the best inhibition performance due to its ability to provide the greatest long-lasting inhibiting effect on the clay surface. When the shale cuttings with the various mud systems were subjected to 150 °C for 16 h in an ageing steel cell, the shale recovery rate at 1.5w/v% concentration confirmed that the PNSC + NH2 exhibited 75.3 wt%, while that of the base mud, KCl, and KCl + HPAM systems demonstrated 33.6, 58.4, and 63.1 wt%, respectively. The BET surface area of the shale reduced significantly by 52.3% with 1.5w/v% PNSC + NH2 from 14.72 to 7.02 m2/g. The wettability determination of the shale surface showed a contact angle of 36.8° which improved to 68.4° by 81.0% with 2.0w/v% PNSC + NH2 concentration. The application of PNSC + NH2 for clay swelling and hydration inhibition proved to be promising and could be effective for drilling shales.

Loading and unloading of a thick-walled cylinder of critical-state soils: large strain analysis with applications

Thick-walled cylinder (TWC) tests are widely used to obtain soil properties and investigate wellbore instability problems in laboratory-controlled conditions. This paper presents analytical cavity expansion and contraction solutions for modelling undrained TWC tests under three typical loading and unloading programs. Both cylindrical and spherical cavities in critical-state soils with a finite radial extent subjected to monotonic loading or unloading under undrained conditions are considered. The solutions are developed in terms of finite strain formulations, and the procedure is applicable to any isotropically hardening materials. Parametric studies show the boundary effect may significantly affect the cavity expansion/contraction response. A limit outer-to-inner diameter ratio of the soil sample exists, beyond which the boundary effect becomes negligible. The limit ratio varies with the cavity geometry, soil stress history (OCR) and cavity deformation level. For undrained TWC tests, a diameter ratio over 20 should normally be adequate to remove the possible boundary effect. Predicted expansion and contraction curves by the new solutions are compared with published data of TWC tests in the literature, and good agreement is shown in each loading/unloading program. This indicates that the boundary effect, which greatly limits the application of conventional cavity expansion/contraction solutions into TWC problems, is successfully captured by the present solutions. The solutions can also serve as valuable benchmark for verifying various numerical methods involving critical-state plasticity models.

Building 1D Mechanical Earth Model for Zubair Oilfield in Iraq

Many problems were encountered during the drilling operations in Zubair oilfield. Stuckpipe, wellbore instability, breakouts and washouts, which increased the critical limits problems, were observed in many wells in this field, therefore an extra non-productive time added to the total drilling time, which will lead to an extra cost spent. A 1D Mechanical Earth Model (1D MEM) was built to suggest many solutions to such types of problems. An overpressured zone is noticed and an alternative mud weigh window is predicted depending on the results of the 1D MEM. Results of this study are diagnosed and wellbore instability problems are predicted in an efficient way using the 1D MEM. Suitable alternative solutions are presented ahead to the drilling process commences in the future operations.

Wellbore Breakouts Prediction from Different Rock Failure Criteria

One of the wellbore instability problems in vertical wells are breakouts in Zubair oilfield. Breakouts, if exceeds its critical limits will produce problems such as loss circulation which will add to the non-productive time (NPT) thus increasing loss in costs and in total revenues. In this paper, three of the available rock failure criteria (Mohr-Coulomb, Mogi-Coulomb and Modified-Lade) are used to study and predict the occurrence of the breakouts. It is found that there is an increase over the allowable breakout limit in breakout width in Tanuma shaly formation and it was predicted using Mohr-Coulomb criterion. An increase in the pore pressure was predicted in Tanuma shaly formation, thus; a new mud weight and casing programs are proposed to overcome such problems in the drilling operations in field developments plans.

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

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

Transient Thermo-Poroelastoplasticity Finite Element Analysis of Inclined Wellbore Stability

Wellbore instability is a crucial concern problem in highly inclined well drilling, extended reach well drilling and horizontal well drilling, particularly in high temperature and high pressure (HPHT) formations. However, few studies have concentrated on the three-dimensional inclined wellbore instability analysis considering the influence of thermo-poroelastoplasticity and filter cake. In the present study, a three-dimensional inclined wellbore stability model fully coupling thermo-poroelastoplasticity and considering filter cake is created and analyzed using finite element analysis. This model can be used for the wells with any deviation angle and azimuth angles simply by changing the far field stresses and boundary conditions. The distribution of pore pressure and wellbore stress under various deviation angles, consolidation time and temperature gradients are investigated. The research results show that, the wellbore instability problem is generally severe in the inclined wells comparing to the vertical wells. The wellbore becomes unstable as the consolidation time increases, and it is more unstable under positive temperature gradient than under negative; the filter cake can reduce the pore pressure and stress around the wellbore, it prevents the wellbore from shear failure in vertical well (deviation 0o), and prevents the wellbore from tensile failure in inclined well especially in the horizontal well (deviation 90o). The results obtained in this paper can benefit a deeper understanding of the instability mechanism of inclined wellbore.

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

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.

The effect of nano coating technique on reduction of clay swelling

Shales make up about three fourths of drilled formation and over 90% of the wellbore instability problems that occur in shales.it still a serious problem in not only the petroleum industry but also in the mining and construction industries. Before any measures are taken to address this problem, it is crucial that potentially problematic formations and the mechanisms of wellbore instability be identified. Once the mechanisms are understood, well planning, drilling fluid design, and drilling operation strategies can be implemented to ensure wellbore stability. Due to the unique mechanical and physicochemical properties of shales, it is well- recognized that wellbore instability in shales is a complicated problem. Shale cuttings consisting of different montomorillonite content were collected from four different wells in Sinai. They were evaluated using X-ray diffraction (XRD), X-ray fluorescence (XRF) and cation exchange capacity (CEC) using Methylene Blue (MB), hence classified into shale 1, 2 ,3 and 4. Swelling index of the shale measured using compressed disks of shale in contact with OCMA bentonite for 20 hrs using the Linear Swell Meter (LSM). Nanoparticles in terms of CuO, Graphene nano platelets and SiO2 used as an inhibitor of swelling of shale cuttings. The inhibitors are added to OCMA bentonite as well. The inhibition of swelling of these shale cuttings using KCl achieved a decrease in swelling that ranged from 15 % at 7 % (shale 1), 14 % at 6 % (shale 2) ,14% at 4% (shale 3) and 17% at 9 % (shale 4)

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.

Laboratory evaluation to assess the effectiveness of inhibitive nano-water-based drilling fluids for Zubair shale formation

While drilling through shale formations, shale hydration, including shale swelling and dispersion, is frequently reported as the main wellbore instability problems, particularly when conventional drilling fluids (water-based) are used. These problems have many adverse effects on the drilling operations resulting in non-productive time. Nanoparticles have been recently introduced as a unique alternative to improve the performance of water-based drilling fluids for shale applications. This paper presents an experimental evaluation to investigate the effectiveness of an inhibitive nano-water-based drilling fluid in reducing the swelling of Zubair shale formation. Well-preserved core samples, which were retrieved from Zubair formation, were characterized using X-ray diffraction, and X-ray fluoresces to quantify the amount of the swelling minerals. Scanning electron microscopy was used to identify the existence of microfractures within the samples. Three different nano-based drilling fluids containing titanium dioxide (TiO2), copper oxide (CuO), and magnesium oxide (MgO) at two different concentrations (0.5% and 1.5% by vol) were evaluated through a set of tests to assess the shale reactivity in the presence of these nano-based fluids. In addition, the effect of these nanoparticles on the rheological and filtration properties was studied. The results showed that the shale samples contain 41.26% silicon dioxide (SiO2) and 22.73% aluminum oxide (Al2O3), indicating the presence of smectite and illite. Based on the reactivity tests, fluids containing CuO at 1.5% by vol outperformed the other fluids in terms of reducing the reactivity, where the expansion rate was reduced by 82.7% compared to the reference sample submerged in fresh water. In addition, the addition of nanoparticles resulted in reducing the plastic viscosity, increasing both the yield point and gel strength, and reducing the fluid loss under low-pressure low-temperature conditions.

Experimental study of nano-drilling fluid based on nano temporary plugging technology and its application mechanism in shale drilling

During drilling operation in gas shales, the high capillary force leads to drilling fluid filtration continuously, which eventually results in severe wellbore instability, reservoir damage, and other problems. To solve this urgent problem, in this study, CaCO3 nanoparticles (NPs) enhanced nano-drilling fluid is developed to reduce the drilling fluid permeation into the shale matrix by sealing. In addition, the sealing nanoparticles can be removed by acid washing to restore reservoir permeability. The size distribution of CaCO3 nanoparticles is determined based on the pore size distribution of the shale matrix. The dispersion evaluation experiments are conducted to select and optimize the type of CaCO3 nanoparticles and dispersion agents. A specially designed pressure transmission experiment is used to evaluate the effects of CaCO3 nanoparticle concentration and rock/fluid contact time on the degree of shale matrix sealing by measuring the matrix shale liquid permeability before and after sealing, and the shale liquid permeability as a function of contact time, respectively. Finally, scanning electron microscope technique is used to explore the sealing mechanism of the CaCO3 nanoparticles enhanced nano-drilling fluid on the shale matrix surface. Results show that 10–40 nm hydrophobic CaCO3 nanoparticles and cetyl trimethyl ammonium chloride are the optimal nano-additive and dispersion agent, respectively. When the optimal nanoparticle concentration is 1%, the reduction rate of the shale matrix permeability reaches up to 95.5%. Moreover, the mechanisms of the nanoparticles seal the matrix pores are discovered: (i) A single nanoparticle can seal the shale matrix pore which has a size similar to the nanoparticle size by plugging method; (ii) Several nanoparticles come together and can seal the shale matrix pore which has a diameter greater than nanoparticle size by bridging method. Finally, after washing by 15% HCl for 30 min, the nano-drilling fluid sealing effect can be removed effectively. This research shows that the NPs could be used as a temporary filtrate reducer in drilling operation of gas shales. In particular, the detailed application mechanism of nano-drilling fluids in shale drilling is presented. The experimental research methods and fundamental data provide significant practical guidelines for the development of new NP enhanced drilling fluids.

Water-based drilling fluid formulation using silica and graphene nanoparticles for unconventional shale applications

The development of unconventional shales started a new era in the oil and gas industry. These reservoirs represent a challenge to conventional drilling fluids since the fluid invasion, cutting dispersion, or shale swelling can lead to wellbore instability problems. Although oil-based drilling fluids (OBM) are capable to control these issues, environmental and economic concerns limit its application. Recently, nanoparticles (NPs) have introduced a new perspective in drilling fluid technology, offering a unique alternative to improve the performance of water-based drilling fluids (WBM) for shale applications. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) to formulate a nanoparticle water-based drilling fluid (NP-WBM). The study considers a bottom-up approach, selecting the NPs based on the Woodford Shale's characterization and focuses its primary objective in finding the most suitable NP combination to enhance the rheological, filtration and inhibition properties of the customized NP-WBM. The shale characterization included X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The zeta-potential technique was used to assess the stability of the NPs. The NP-WBM was evaluated by means of API filtration test (LTLP), high-temperature/high-pressure (HTHP) filtration test and rheological measurements using a conventional viscometer. Finally, the inhibition capability of the NP-WBM was tested against the Woodford shale through immersion and cutting dispersion tests. NPs' characterization revealed that both additives can provide stable suspensions with zeta-potential values < −30 mV. A total NP concentration of 0.75 wt% (0.5 wt% of SiO2-NPs and 0.25 wt% of GNPs) yielded to the maximum reduction in filtrate volume at both, LTLP and HTHP conditions. The less permeable filter cake resulted in no spurt-losses, supporting the NPs' plugging effect. A strong cross-linked network created between the NPs and the conventional additives increased the cutting carrying capacity of the NP-WBM with slight effects on its plastic viscosity (PV). The immersion test carried out in water revealed that illitic shales might experience micro-fractures along the bedding planes in the absence of bridging materials. Contrarily, the NP-WBM provided an adequate plugging network between grain boundaries, resulting in no micro-fractures, and the reduction of the cutting erosion by 35.61%. Overall, this study highlights the capability of nanomaterials to extend the reliability of WBM to harsher environments while seeking an eco-friendlier alternative.

Modelling of Time-Dependent Wellbore Collapse in Hard Brittle Shale Formation under Underbalanced Drilling Condition

In recent years, the lithologic traps in a mid-depth formation are the focus of oil or gas exploration and development for eastern oilfields in China. The Shahejie Formation develops thick hard brittle shale, and the wellbore instability problem is prominent due to obvious hydration effect for long immersion time during drilling. Through the analysis of laboratory tests and field test results of physical and chemical properties and microstructure and mechanical properties of hard brittle shale, the instability mechanism is discussed for the wellbore in the shale formation. To simulate the whole process of progressive collapse of a wellbore in a hard brittle shale formation, a coupled hydraulic-mechanical-chemical (HMC) model is developed and this model is compiled with ABAQUS software as the solver. Then the coupled HMC model is applied to simulate the progressive evolution process of wellbore collapse in a hard brittle shale formation, and the influence of different parameters on the progressive failure of the wellbore is analysed. The results show that the wellbore enlargement rate increases with the drilling fluid immersion time and the influence of different parameters on the wellbore enlargement rate is different. The water absorption diffusion coefficient and the activity of the drilling fluid have the most obvious influence on the expansion of the wellbore, and the sensitivity is strong. The permeability of shale has little effect on the wellbore enlargement rate. The calculated progressive failure process of the wellbore is basically consistent with that of the actual drilling.

Fe3O4/poly (acrylic acid) nanoparticles as modifiers for improving rheological and filtration properties of water-based drilling fluids

Drilling fluid is a vital element and is often regarded as the “blood” in the oil industry. Although traditional oil-based drilling fluids have advantages in some harsh cases, the high cost and environmental pollution faced with them limit its application. Water-based drilling fluids (WBDFs) with environmental friendly, low cost, and high performance are important for drilling engineering to solve the problems of low efficiency and wellbore instability caused by poor rheological properties and large filtration loss in drilling operations. In this paper, Fe3O4 nanoparticles modified by poly (acrylic acid) (PAA) through 3-(trimethoxysilyl) proryl methacrylate (TMSPMA) were introduced into WBDFs for enhancing their rheological and plugging performance. Rheological tests indicated that the consistency coefficient (K) of the Fe3O4/PAA nanoparticles/WBDFs decreased at a higher concentration. Incorporated nanoparticles with a concentration of 0.05 wt %, the WBDFs will exhibit good shear-thinning behavior. The results showed that the best performance for Fe3O4/PAA nanoparticles being as a filtration additive in WBDFs was achieved at concentration as low as 0.1 wt %. These results demonstrated that Fe3O4/PAA nanoparticles are effective additives for WBDFs.

Modeling progressive breakouts in deviated wellbores

Borehole breakout is a progressive failure process that results in major wellbore instability problems. Previous studies of progressive breakouts have been mainly for vertical wells, with fewer studies for deviated wells. Moreover, most existing breakout models cannot update the boundary conditions for the receding wellbore surfaces during progressive breakout propagation. This paper presents a finite-element-based method for simulating dynamic breakouts in deviated wellbores considering hydro-mechanical coupling. By incorporating an adaptive meshing technique, the method allows for timely updates of the boundary conditions on newly created wellbore surfaces due to breakout. Using the proposed method, the effects of well trajectory, in-situ stress anisotropy, fluid seepage, and formation properties on wellbore breakouts in a strike-fault stress regime are investigated. The results are analyzed in terms of the orientation and magnitude of wellbore breakouts. The analysis shows that breakout orientation on the cross-section plane normal to the axis of a deviated well is always aligned with the projection of the minimum horizontal stress direction on this plane. A smaller Young's modulus, a smaller cohesion, or a larger permeability increases the risk of borehole breakout.