Flow rate (Q) affects many drilling operations and parameters such as equivalent circulation density (ECD), hoisting and lowering the drillstring, and breaking gel strength during circulation. The aim of this work is to understand the relationship between ECD and Q based on flow regimes (e.g. laminar, transitional, and turbulent) to avoid or at least minimize the unwanted consequence during drilling practice. Field data from over 2000 wells drilled in Iraq were collected and analyzed to identify the physical relationship between flow regimes and ECD to enhance the drilling rates. After visualizing the whole dataset, a decision was made to break down the data into three parts based on flow regimes (e.g. laminar, transitional, and turbulent). Descriptive data mining techniques were utilized to establish the relationship between flow regimes and ECD. By achieving better control of ECD in the well, not only faster and cheaper operations are possible, but also safety will be improved. Previous studies and literature showed that flow regimes can tremendously affect ECD. Many studies have been conducted to understand the relationship between Q and ECD. Nevertheless, the consideration of flow regimes was not implemented in these studies. Inconsistency in the literature results was identified, some concluded the relationship between Q and ECD to be direct, and others showed it to be inverse. Thus, this paper will eliminate this discrepancy in the literature, and it will show that the flow regimes have a pivotal role in the relationship between Q and ECD. The results of this paper showed that if the flow regime is laminar, the relationship between ECD and Q is inverse. However, in transitional and turbulent flow regimes, the relationship between ECD and Q is direct. That is because, in the laminar flow regime, the cutting will fall out of suspension due to low Q, which will cause a cutting bed to be built and decreases ECD. As Q increases (entering the transitional and turbulent flows) the cutting bed will be eroded, and most of the cuttings will be suspended in the fluid which will increase ECD. This study examines and expands the understanding between how the characteristics of flow regimes affect ECD. Additionally, this paper will eliminate the discrepancy in the literature about this relationship between ECD and Q.

It is not easy to obtain an optimal hole cleaning for the drilling operation because of the complicated relationship between the drilling parameters influencing hole cleaning. The two viscosity components (e.g. plastic viscosity (PV) and yield point (YP)) and the flow rate (Q) are essential parameters for effective hole cleaning. Thus, understanding the relationship between those parameters will contribute to efficient hole cleaning. The aim of this paper is to explore those relationships to provide optimal hole cleaning. Descriptive data analytics was conducted for data of more than 2000 wells drilled in Southern Iraq. The data were first cleansed and outliers were removed using visual inspection and box plots. The Pearson correlation (PC), a widely used method to measure the linear relationship between two parameters, was utilized to access the relationships between PV and Q, YP and Q, and YP/PV and Q. Moreover, a 10% sensitivity analysis was escorted to quantify and comprehend those relationships. The PCs were calculated to be 0.5, 0.076, and 0.22 for the relationships between YP, PV, and YP/PV with Q, respectively. YP had the highest direct relationship with Q, while PV had the lowest. When the YP increases, a sufficient Q has to be provided to initiate the flow and maintain the mud cycle. In addition, to prevent large solid particles from settling due to the slip velocity, sufficient annular and particle velocities have to be achieved. After initiating the flow, an increase in flow rate to overcome resistance due to PV will not be significant. Therefore, YP has more effect on Q than PV. To maximize hole cleaning, thickening ratio (YP/PV) should be increased. This requires an increase in flow rate, which can be quantified by using the sensitivity analysis provided to achieve the required Q for any increase in YP/PV.

One of the critical issues that might happen in some oil and gas wells is the failure of the cement sheaths and its debonding from the casing string. Cement shrinkage during setting is regarded as one of the main causes behind formation of microannulus cracks. In this paper, a new class of polymer-based expandable additives is presented in the form of fibers to address shrinkage and debonding issues in the subsurface. The proposed fiber additives are made from shape memory polymers. These fibers expand upon exposure to temperatures above certain limits; which is selected to be below the temperature of the cementing zone. In this situation, the expansion occurs before the cement setting but after its placement. If the expansion occurs after cement setting, it may lead to microfractures. As a result of the controlled expansion of the cement paste, the creation of channels and fluid migration can be minimized while maintaining the mechanical properties required for cement integrity. Considering the inert property of the proposed additive, the cement water ratio and its chemical properties do not change. The cement expansion, fluid loss, gel strength, compressive strength, and tensile strength of the samples containing these fibers are examined by destructive and non-destructive methods and presented here. The proposed class of expandable additives can help the operators reach sustainable well integrity by improving the bonding between the cement and casing.

Drilling problems such as stick slip vibration/hole cleaning, pipe failures, loss of circulation, BHA whirl, stuck pipe incidents, excessive torque and drag, low ROP, bit wear, formation damage and borehole instability, and the drilling of highly tortuous wells have only been tackled using physics-based models. Despite the mammoth generation of real-time metadata, there is a tremendous gap between statistical based models and empirical, mathematical, and physical-based models. Data mining techniques have made prominent contributions across a broad spectrum of industries. Its value is widely appreciated in a variety of applications, but its potential has not been fully tapped in the oil and gas industry. This paper presents a review compiling several years of Data Analytics applications in the drilling operations. This review discusses the benefits, deficiencies of the present practices, challenges, and novel applications under development to overcome industry deficiencies. This study encompasses a comprehensive compilation of data mining algorithms and industry applications from a predictive analytics standpoint using supervised and unsupervised advanced analytics algorithms to identify hidden patterns and help mitigate drilling challenges. Traditional data preparation and analysis methods are not sufficiently capable of rapid information extraction and clear visualization of big complicated data sets. Due to the petroleum industry's unfulfilled demand, Machine Learning (ML)-assisted industry workflow in the fields of drilling optimization and real time parameter analysis and mitigation is presented. This paper summarizes data analytics case studies, workflows, and lessons learnt that would allow field personnel, engineers, and management to quickly interpret trends, detect failure patterns in operations, diagnose problems, and execute remedial actions to monitor and safeguard operations. The presence of such a comprehensive workflow can minimize tool failure, save millions in replacement costs and maintenance, NPV, lost production, minimize industry bias, and drive intelligent business decisions. This study will identify areas of improvement and opportunities to mitigate malpractices. Data exploitation via the proposed platform is based on well-established ML and data mining algorithms in computer sciences and statistical literature. This approach enables safe operations and handling of extremely large data bases, hence, facilitating tough decision-making processes.

In the late summer of 2009 an American oil and gas producer teamed up with a Canadian pumping service company and performed a series of Liquified Petroleum Gas (LPG) fracturing treatments in Pennsylvania's Marcellus Shale. A total of four stages were pumped on three different vertical wells in three different counties Centre, Lycoming, and Indiana. Questions surrounding damage associated with pumping large volumes of fresh water in nano-to-micro Darcy shale along with environmental pressures about water supply and disposal led to consideration of an alternative, non-aqueous fracturing fluid. A hydraulic fracturing process utilizing 100% LPG as a fracturing fluid to carry proppant into shale or a coal seam or other water sensitive pay zone was developed. The new LPG fluid could be easily viscosified with oil gelling chemicals allowing for excellent proppant transport. LPG was an appealing choice of fracturing fluid because its phase behavior in the Marcellus Shale at bottomhole conditions would theoretically render it non-damaging. The fracturing process brought sand into the gelled LPG so that it could be pumped under high pressure and into created fracture geometry in a pay zone. With respect to well cleanup post-frac LPG held the promise of greater cleanup and improved effective fracture half-lengths. This paper will provide details about the LPG fracs and the resulting production response using a mix of readily available public domain information and information obtained by service providers or vendors. Initially, it was author's intention to use only public data but changes in the local market made access to more information available. A comparison of LPG fracturing treatments with slickwater treated wells will be shown for two of the three wells. Concluding remarks will discuss the current state of LPG fracturing in North America and a possible explanation for production results that did not meet expectations.

Narrow annulus is frequently encountered in drilling operations as in Casing while Drilling, Liner Drilling etc. Hydraulics of narrow annulus is a relatively new topic of research in drilling. Current analytical solutions have limited applicability for complex flow regimes affected by casing motion, pipe rotation, eccentricity and cuttings. Therefore, the objective of this research is to develop data-driven statistical learning models which can be very effective in making pressure loss predictions for given operating conditions. The data for proposed supervised learning was obtained from large scale experiments conducted on a narrow annulus wellbore configuration on LPAT (Low Pressure Ambient Temperature) flow loop at TUDRP, Tulsa University Research Projects Group. Exploratory visualizations were used to determine the relationship between operational parameters and pressure drop. Resampling methods, such as cross-validation and bootstrapping, were used to split the dataset into training and test data. Shrinkage and Decomposition technique was applied to make multivariate regression more robust. Comparison was made between different algorithms to determine the best model in terms of Least Mean-Squared-Error (MSE) on test data prediction and interpretability. Multivariate exploratory plots were used for data inference. Relationships between different factors and annular pressure drop were mostly linear. As expected, pressure drop increased with increase in flow-rate, inclination angle, ROP and for non-Newtonian polymeric fluids. Principal Component Analysis (PCA) was performed to reduce the dimensionality of the data set. Approximately 98% of variance in data was explained by 5 principal components and the resulting model produced a MSE less than 1% of median pressure drop. Even though PCA regression model performed well on test data, final model was more difficult to interpret because it does not perform feature selection or even produce coefficient estimates. Therefore, Partial Least Squares (PLS) regression was used which gives better model interpretability as it is supervised by feature-outcome relationship. Shrinkage methods-Lasso and Ridge Regression were also used. These methods add an additional penalty term to Least Square Regression to get a bias-variance tradeoff. Cross-validation was used to select the penalty term that gave the lowest MSE. Both methods produced competitive MSE but performed better than PCA and PLS regression. In conclusion, Lasso-Regression performed the best with lowest error and good interpretability.

A drilling team has focused on increasing lateral lengths in the Marcellus Shale over the past couple of years. The team reevaluated prior drilling processes that had been in place for 7,000’ to 9,000’ laterals in order to determine what operational practices would need to be revised in order to drill and case laterals in excess of 18,000’. We focused on rig upgrades, directional tools, drilling fluids, casing floatation and other best practices. We even implemented field trials on various lateral lengths in efforts to evaluate extended lateral practices prior to drilling the first 18,000’ lateral. Over the twelve month period of revised processes and upgrades, we drilled thirty-four horizontal wells each exceeding 12,000’ in lateral length – this included two wells in excess of 17,850’ with one exceeding 18,000', which represented the first drilled Marcellus lateral to exceed that length. This paper covers the details of those processes and upgrades that led to dozens of successful Marcellus horizontal wells with extended lateral lengths.

Unconventional shale resources are drilled horizontally following the geologic bed dip upward or downward and completed with multi-stage fracturing to maximize reservoir contact. A recent study in Oklahoma claimed that toe-up (inclined upward) laterals yield the highest production rate and estimated ultimate recovery. The objective of this study is to investigate drilling fluid hydraulics and well control operations in toe-up laterals and compare the results to toe-down laterals. This study uses a multiphase steady-state hydraulics and a dynamic well control simulator. A hydraulics model was developed and verified with a data from a recently drilled Marcellus shale lateral in Monongalia County, WV in 2015. Static and dynamic pressure profiles were examined at drilling flow rate and at slow pump rate. Further, this research studies gas kick behavior and well control practices for kicks experienced at shallow, middle, and deep zones in the lateral section. Additionally, it considers the impact of operational parameters and influx characteristics on wellbore integrity. The results of this study showed that the developed hydraulics model successfully predicted the pump pressure with an accuracy of 0.97. Larger kick sizes result in higher pit gain, gas flow rate, choke, and casing shoe pressures in toe-down laterals. In contrast, in toe-up laterals, the higher the kick size, the longer the circulation times with an insignificant impact on the choke and shoe pressures. In toe-up laterals, gas bubbles migrated towards the toe and accumulated in high side pockets. Likewise, choke experienced less pressure, volume, and gas discharge rate for extended periods of time in toe-up laterals. Therefore, higher circulation rates and longer circulation times were essential to flush out the dispersed and trapped gas bubbles. The closer the kick location to the vertical section of the well, the shorter the circulation time needed. However, kicks experienced at the heel resulted in higher pit gain, gas discharge rate, choke pressure, and consequently high casing shoe pressure. Identifying the consequences of drilling toe-up laterals on hydraulics and well control is crucial for drilling operations. This improves rig and personnel safety and reduces the blowout associated risks. Accordingly, it is critical to verify the well integrity by monitoring surface choke, casing shoe, and constant bottomhole pressures throughout the entire well control operations.

Nanomaterials are the new additives for drilling fluids that can improve its properties and eliminate problems due to increased downtime and well costs. The objective of this research is to select the optimum concentration of nanoparticles that enhance drilling fluid properties and hydraulics. This study investigates the effects of commercially available nanoparticles on the rheological and filtration properties and optimizes the hydraulics of water-based drilling fluids. In this study, the samples were prepared as water-based muds with and without various concentrations of 5.7 nm colloidal silica dioxide nanoparticles. Series of laboratory experiments were carried out for all samples using standard API Low Pressure Low Temperature (LPLT) filtration and rheological tests. Two mud systems at different pH conditions were used to evaluate the impact of nanoparticles. A commercial software was used to evaluate the impact of the nanoparticles on the Equivalent Circulation Density (ECD) and the circulation pressure loss in a deviated wellbore. Results show enhancements in the rheological and filtration properties for water-based muds treated by the nanoparticles used in this study with concentrations below 0.7% by weight. Furthermore, the results show the ability of these nanoparticles to make the filter cake consistent, compacted, and thin. The results reflect the negative impact of the nanoparticles with concentrations above 0.7% by weight on some of the rheological properties. The optimum nanomaterial concentrations with the best properties were observed as (0.1%-0.3%) by weight. Furthermore, the concentration of 0.1% by weight reflected the significant reduction in the ECD and the circulating pressure loss. Nanoparticles used in this research can play a vital role in reducing drilling problems. Multilateral wells, slim holes and deep horizontal wells can be drilled by using water-based mud with the addition of proper nanoparticles and eliminating the need for oil-based muds that are expensive and environmentally unacceptable. However, it is critical to select the proper size and concentration of nanoparticles in order to eliminate its negative impact on the drilling fluid properties.

A numerical approach is presented to simulate the non-Newtonian flow of a wellbore cementing process to quantify the potential for poor drilling mud displacement efficiency and bond strength development between the cement annulus and rock formation. The approach consists of using the lattice Boltzmann method with a Bingham plastic constitutive model to represent the cement flow behavior. The lattice Boltzmann method is a pseudo-particle, mesoscale approach that naturally models complex flows in a computationally efficient manner, but has thus far seen limited use for capturing such slurry (or similar) flows. Results from the model are presented for a wellbore cementing process with various annular configurations and cement slurry properties. In particular, the results consider irregularities and imperfections in the shape of the rock formation surface, as well as changes in the cement flow properties (e.g., viscosity), as could be affected by variations in mix and/or the pumping process. These results show an array of circumstances in which poor drilling mud displacement efficiency and bond strength development between the cement column and rock formation does or does not occur as the cement is pumped into the wellbore annulus. Lastly, potential future work and developments are discussed for the numerical approach to address other failure mechanisms of zonal isolation, which are still poorly understood mechanistically.

Objective of this study is to shed light to critical well control parameters of horizontal shale gas wells drilled with oil based muds (OBM). This study utilizes an interactive well control simulator to re-evaluate the kick control procedures in water based mud (WBM) and verify its application to oil based mud. Due to gas solubility in OBM a real time drilling and hydraulics data analysis is essential to minimize kick volumes. Therefore, early kick detection and surface warning signs are critical to minimize the influx size and reduce wellbore pressures. Moreover, the impacts of water-to-oil ratio, gas solubility, kick size, influx type and circulation rates on well control are investigated. OBM kick control process in horizontal wells creates additional challenges since the surface pressure and volume are not representative of the bottom-hole conditions. In unconventional shale gas reservoirs, oil and synthetic based drilling fluids are very common. Drilling cost, log interpretation, and environmental impacts are the main drawbacks of OBM. However, wellbore stability, reduction in torque and drag, stability of mud properties at higher temperatures and better drilling performance are the main advantages of OBM. Preliminary results show that dissolved gas in oil is liberated at the bubble point pressure and complicates surface kick handling procedures. Choke adjustment is hard due to the unexpected high volume of gases released and the delay time of choke response. Early detection is a key factor in minimizing the influx size and properly controls the casing shoe and choke pressures. Based on 110 hours of real time interactive simulation, influence of gas solubility on well control in OBM is presented to improve rig and personnel safety and reduce the blowout associated risks.

Currently, there are few available publications regarding the application of nanotechnology in fluid loss control; hence, this technology needs more exploration. During hydraulic fracturing, fracture conductivity damage and other problems associated with excessive leak-off rate can be significantly curtailed by utilizing nano-fluid systems that evolve from further research studies. An experimental study is presented on the application of nanotechnology on filtration properties of surfactant-based fluids (SBF), polymeric fluids, and SBF-polymeric fluid blends. The concentration of SBF is 5%, while that of polymeric fluids is 33 lb/Mgal guar. Besides, both fluids contained 4% potassium chloride (KCl). Additionally, Blend-A and Blend-B were prepared by mixing SBF and polymeric fluids in the ratio of 75/25% vol. and 25/75% vol. respectively. Nano-fluids were prepared by adding 20 nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4% wt., to the clean fluids. Filtration tests were conducted with a wall mount filter press, and at ambient temperature and 100 psi differential pressure. Excellent results were displayed with surfactant-based nano-fluids and Blend-A nano-fluids, but their outcome at 0.24 and 0.4% wt. respectively is slightly better. Polymeric nano-fluids and Blend-B nano-fluids revealed very good results, with better outcome at 0.24 and 0.058% wt. respectively. A trial run was made with a commercially available fluid loss additive (polyanionic cellulose, PAC) in polymeric fluids at the same nanoparticle concentrations; the result confirmed that nanosilica facilitates the achievement of a superior filtration property. Furthermore, Blend-A nano-fluid, at 0.058% wt., is selected as the best based on performance evaluation and economic analysis. In conclusion, the selected Blend-A nano-fluid at 0.058% wt. was optimized at lower nanoparticle concentrations (0.02, 0.01 and 0.002% wt.) in order to probe further into its filtration performance. Interestingly, using Blend-A nano-fluid at 0.002% wt., as regards the initial recommendation of 0.058% wt., reduces the cost of nanoparticles required for preparing 1 barrel of this fluid by 96.6%. Therefore, Blend-A nano-fluid is recommended for use at nanoparticles concentration of 0.002% wt. The application of Blend-A nano-fluid will promote fluid economy, substantially reduce fluid loss and fracture conductivity damage, and enhance production from unconventional reservoirs.

Rheological experiments have been conducted with commercial and experimental friction reducers indicating certain profiles are advantageous for performance. In these profiles the factors of time and concentration are important in predicting the maximum performance window. These windows become apparent without the use of sophisticated rheological instrumentation. The viscosity profile of a friction reducer is dependent on factors such as polymer charge, charge distribution, molecular weight, polymer concentration, solvent properties, specific shear rate and time. Often it is difficult to measure properties such as molecular weight and viscosity, both quite sensitive to the specific test method and many assumptions are made. In this study, the viscosity of the system depends on the shear history, concentration, and time of measurement. Most traditional viscosity methods assume a thermodynamic definition of polymer configuration. This assumption is valid for measurement of friction reduction after significant duration. However, in a hydraulic fracture, this time may not be realized during the volumetric transfer of the fluid from the pumps to the perforations. In a recirculating friction loop measurement, the friction reduction performance of an ideal candidate rapidly increases and then sometimes diminishes with recirculation time. A possible correspondence between this phenomenon can be linked to the measurement conducted in this study. Shear rate sweeps were conducted on a variety of synthetic polymers with a Couette rheometer and a microchip rheometer. Variables studied were polymer type, concentration, shear history, time, solvent, make-down procedure, and atmosphere. Both inverse emulsion and dry friction reducers were studied. Friction reduction was measured on a once through system. From this study, ideal friction reducer candidates can be selected by simply and rapidly examining the rheological profile and rheological nuances realized when conducting the measurements. When choosing an ideal friction reducer, it must perform rapidly and maintain the necessary friction reduction required for the time frame needed.

Long-term zonal isolation provided by cement is a crucial task in the life of oil and gas wells. However, significant number of primary cementing jobs experience problems; particularly in highly deviated wells, extended reach wells, and wells prone to severe washouts. Primary cementing efficiency has attracted more attention since the development of shale gas industry and the Macondo Blowout in the Gulf of Mexico. Sustained casing pressure reported in some of the wells in Marcellus shale play and the root of several blowouts is attributed to cementing job performance. Therefore, studies on the performance of cementing operations are essential in restoring the public opinion on petroleum industry by addressing problems that have major social, environmental and economical consequences besides the technical interest. Casing is prone to deviate toward the bottom of the well especially in horizontal wells. This eccentric annular space leads to annular velocity disturbance in favor of wider region of the annulus. Finally, part of the narrow section of annulus would be left un-cemented. The bypassed mud is potential path for the formation fluid communication with other formations or to the surface. Poor cementing can affect the hydraulic fracturing job as well. This paper is part of a comprehensive three-dimensional time-dependent computational fluid dynamics (CFD) model developed to account for dominant parameters affecting the mud displacement process in horizontal wells. Parameters such as casing eccentricity, cement yield strength, cement plastic viscosity, the density difference between mud and cement, pumping rate and washout are studied. The effects of the first three parameters are addressed in this paper. Current best cementing practices have deficiencies in providing excellent cementing efficiency. Therefore, a novel technique, using Magneto-Rheological fluid, is also proposed to improve the displacement efficiency. Magneto-Rheological fluid can act as a plug in the wider region of annulus under magnetic field applied through the casing. Consequently, flow will be directed to the narrower annular region that could not be cemented or cleaned otherwise. The results are appealing and further study on application of Magneto-Rheological fluid in petroleum industry is suggested.

Shale makes up 75% of drilled formations and causes over 90% of wellbore instabilities. Although drilling fluids with acceptable performance in Shale have been formulated, the industry is still endeavouring to formulate an optimum inhibitive drilling fluid for the Marcellus Shale. In accordance, this research seeks to fabricate a means of reducing formation damage (permeability reduction leading to poor hydrocarbon production), stuck pipe incidences, heaving, sloughing and caving which are all due to the swelling of Smectite clay and shale. This research paper, in its infinite practicality, expounds upon the predicaments associated with swelling and dispersion of shale, the chemistry behind the swelling/dispersion of shale, justification of this research and the results obtained from laboratory work and experiments, experimental procedures performed in the formulation of an optimum inhibitive drilling fluid for the Marcelus Shale such as rheological, filtration and linear swelling experiments. Most importantly, this paper introduces a novel approach and experiment towards the development of an optimum inhibitive drilling fluid, utilizing a novel chemical in the industry: ω-α Diamino Alkanes (Diamino Butane and Diamino Hexane) as well as comparing the inhibitive capability of two familiar chemicals in the industry in conjunction with Chlorides and Hydroxides of numerous Alkali metals, Alkaline earth metals and Transition metals (K + , Na + , Ca 2+, Mg 2+ , Li + etc) in various concentrations. The rheological, shale inhibition and filtration effects of the aforementioned Hydroxide and Chloride chemicals were tested and examined which led to the subsequent elimination and selection of certain fluids which this research has recommended for testing in Marcellus Shale formations in West Virginia and similar shales in the globe. Universally acceptable filtrate loss correlations have been formulated, during the course of this research, for various base drilling fluids. Finally, it was observed that a drilling fluid system comprising of KCl, Diamino Hexane and Bentonite was effective in reducing shale and Smectite swelling when compared to the currently leading inhibitive mud currently used in drilling shale formations. This research project was limited to the Marcellus Shale formation in the State of West Virginia and the results obtained from the inhibition/swelling tests may not be universally acceptable in the evaluation of other shale formations. However, the generated rheological and filtrate loss results and correlations may be universally applied.

Instability issues often occur when water-based muds are applied to shale formations. Failure to predict the pore pressure accurately has been widely accepted as one of the major reasons causing shale instability. Water activity is a key factor to control the pore fluid moving in and out of the formation due to osmotic effects. Ideal and single-solute models have been developed in the past to predict the pore pressure by considering chemical osmotic effects. However, due to their complex nature, pore fluids/drilling fluids rarely behave as ideal solutions. A new model has been developed to predict pore pressure in shale formations that takes into account the non-ideality and multiple solutes of both drilling fluid and pore fluid. Transient pore pressure profiles and water activity are obtained from the coupled equations developed in this study. A Shale-Fluid Interaction Testing Cell (SFITC) has been developed in this study to test the interaction between the drilling fluid and the pore fluid. Parameters involved in the model, such as hydraulic conductivity, membrane efficiency and ion diffusion rate can be obtained through experimental data curve fitting. Model predictions have been compared with lab data and good agreement has been achieved. Water activity is found to be crucial for pore pressure control in shale formations. Simulation results explain the fact that salinity of drilling fluids has to be controlled in order to achieve shale stability. Results of this study can benefit drilling fluid design. Shale instability can be reduced by "balancing" the water activities of shale and drilling fluid. This can be achieved through changing the type of solutes and their concentrations based on information of the initial water activity of the shale. Wellbore stability models can obtain more accurate results by including the proposed pore pressure propagation model, which considers drilling fluid-induced chemical osmotic in-situ stress.

This paper presents a technology for water-based drilling fluid that is weighted with calcium carbonate. This technology has both functions of drilling and completion fluids and can reach to the total depth of MRC wells. It creates a filter cake that prevents fluid leak off and formation damage during the drilling process, but readily cleans up the filter cake over time. This technology is based on the use of an ester, in a solid form, which hydrolyzes and produces an organic acid. The latter will dissolve calcium carbonate particles that are used as a weighting material in water-based drilling fluids. Polylactic acid (PLA) particles were used in the present study to generate lactic acid. Experiments were conducted to find an optimum particle size of the solid ester and calcium carbonate particles that should be selected as a compromise between those that are optimal for fluid loss control or filter cake formation and those that are optimal for self-destruction at the desired time and rate. Other set of experiments were conducted to determine the temperature and soaking time required for the solid ester to hydrolyze and for the resulting acid to dissolve calcium carbonate particles. All experiments showed that in a controllable-condition of temperature, acid concentration, and particle size the clean up efficiency exceeded 70%. The optimum particle size was found to be 50 µm calcium carbonate and 150 µm PLA. The optimum temperature was 230°F for running experiments due to high filter cake removal efficiency, low filtrate volume and not having returned mud high viscosity problems. Enough soaking time is needed for PLA to be hydrolyzed and for the acid to remove the filter cake (20 hours).

Shale gas plays are very active and there is little time available for the practicing engineer to spend on well studies that would describe the effectiveness of particular treatment chemical additives. Each shale play has variations within its own lithotypes and mineralogy suite, not to mention that shales differ from each other individually in key mineralogical and geomechanical measures. These differences in lithologies, mineralogies and geomechanics within the formation itself should be evaluated to develop a minimum standard application for fields. Particular attention should be paid to the clays as they are the most ion-influenced components of the rock. Clay minerals in shales seem to be misunderstood in some cases. Lithologies and clay mineral suites that should require minimal temporary and/or permanent clay protection are being disproportionately treated with expensive clay protection chemicals. By evaluating the geologic age, formation temperature, mineralogy, Brinell hardness, and Capillary Suction Time test results one can draw some conclusions about clay responses to fluid exposure. Using the results of these analyses in conjunction with previous experience and other independent well data can give reasonable information to make proper fluid selections in shale reservoir completions. The results presented in this study show very different responses for several different clay protection chemistries when tested on shales of known clay content. Although most of the shales studied here contain very little, if any, swelling clay, certain additives yielded a questionable response. The study presents both test results and laboratory evaluation techniques for selection of clay protection chemical additives and economical considerations in shale reservoir completions.

Recent studies involving the measurement of friction reducer performance with a variety of brines typical of flow back/recycled stimulation waters of the North Eastern United States have indicated a clear differentiation by specific product type. The friction reducer variances specifically studied were: product charge, charge type, charge distribution reflective of polymerization, molecular weight, inverse emulsion surfactant packages, and manipulation of the internal or external phases. Increasing environmental regulatory pressure in geographic regions sensitive to water use, stimulation flow back discharge, and an increasing need for recycled water, the Marcellus gas play for example, have created a greater demand for higher performing additives in fluid systems used for oil/gas well fracturing. One additive that is greatly influenced by brine characteristic and water quality is the friction reducer. Increasing the ionic strength as well as multivalent cation content of the water typically limits the type of friction reducer used to obtain optimum performance. Standard anionic friction reducers do not perform well in many of these recycled waters as the friction reducer’s ultimate performance is decreased, but also the rate of inversion is retarded and the potential for formation damage is increased. When compared to standard friction reducers, the ultimate friction reduction of the best of the series studied achieved nearly twice the friction reduction, approaching Virk’s theoretical limit, and had an inversion rate nearly four times as rapid as a standard friction reducer. The dosages of the friction reducer were from 0.25 to 1.00 gallons per thousand gallons of treatment fluid. These friction reducers were tested in a variety of brines in a 10 gallon capacity friction loop through a ½ inch pipe at a Newtonian Reynolds number of 150,000. The data was collected every second during a 10 minute run with 6 specific performance criteria used to rank the candidates. This study demonstrates it is possible to provide a friction reducer that works well in brine content typical to stimulation fluids that contain a majority of flow back water from previous well treatments. This would allow well service companies to provide quality stimulation fluids of greater brine content and also minimize fluid disposal volumes and affiliated costs. Chemical additives such as these are needed in regions where both water quality and quantity are concerns.

Abstract The success of producing gas from unconventional resources, such as shales, is often tied to maximum exposure to the reservoir. Usually this is achieved by drilling horizontal wellbores and creating fractures that originate from multiple points along the wellbore. Each fracture "stage" must be isolated from the previous stage so as to create additional unique flow paths for the gas. One mechanism to create the fracture isolation points is to use chemical swelling packers between the liner and the formation. These chemical swelling packers can be swollen using water-based fluids, hydrocarbon-based fluids, or combinations of both. Certain shale formations, like the Lower Huron and Marcellus, are often drilled with air or foam. One reason for air drilling is that these formations have shown a propensity to incur damage from traditional drilling fluids (both hydrocarbon- and water-based). Because of this, there can be reluctance to use traditional fluid systems to activate chemical swelling packers in these formations. This paper documents the laboratory investigation and development of a novel activation fluid system that minimizes the potential damage to the reservoir but still permits operations to take advantage of the unique characteristics of the chemical swelling packer. Included is a discussion of the operational issues encountered to "scale up" for the first field trials and the results of the first commercial applications. Background Packers for zonal isolation are commonplace fixtures in subterranean wells. Packers can be set through a variety of mechanisms that include mechanical, hydraulic, inflatable, or chemical swelling. The swellable packers offer many advantages over more conventional packers, which include the ability to adjust to irregular borehole geometries, overgauge hole, other wellbore incongruities, and lower running profiles, just to name a few (Evers et al. 2008; Yakeley, Foster, and Laflin 2007). However, one disadvantage is that sensitive formations have the potential to be damaged by the swelling fluid, as the formation is often in contact with the fluid for an extended period of time. Fig. 1a is an illustration of a swellable packer in an open hole. The packer string is run downhole, and an activating fluid is circulated into the annulus. Over a period of time, the packer elements will respond to the fluid and swell to seal against the formation. After the packer has swollen to sufficient dimensions to establish an isolation point, the production casing can be perforated and fracture stimulated (Fig. 1b). As the completion techniques advance using swell technology, many wells avoid perforating time and expense by incorporating a sliding sleeve to provide access to the reservoir. Upwards of 15 sliding sleeves and 16 swelling element packers have been used to create 15 unique and individual fractures within the pay zone. This combination of simple, reliable tools functions equally as well in horizontal and vertical wells (Yakeley, Foster, and Laflin 2007). It is typical for the fluid to be in contact with the formation for one to two weeks. The fluid acclimates to the bottomhole static reservoir temperature during that time frame.