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.

Throughout multiple shale plays, high viscosity friction reducers (HVFRs) have successfully placed more proppant mass with lower treating fluid volume; thus, the industry is accelerating adoption of these treating fluids. Previous published studies have included treatments in Bakken shale and Permian Basin formations. The characteristics of the Marcellus shale make it particularly beneficial to minimize water and gel injection into the formation. At the same time, operational constraints related to smaller footprint and pad sizes in the Marcellus region make it beneficial to reduce gel hydration equipment on location. In spite of these potential benefits, application of high viscosity friction reducers has only recently begun in the Marcellus region. One factor delaying the introduction of HVFRs into the Northeast has been the challenging waters and brines often used in treatments. This study documents the successful introduction of a brine tolerant, high viscosity friction reducer with multiple operators in the Marcellus region. Marcellus operators compared several different friction reducer chemistries through field trials on multiple pads. Based on measurements of surface treating pressure and proppant placement, an optimum fluid system was selected that is effective in a range of water qualities and allow increased pump rate. The friction reducer was also compared to conventional gel technology based on the same method. The brine tolerant friction reducer was found to be an effective replacement for linear gel fluids and allowed reduction of equipment on location. A brine tolerant, high viscosity friction reducer enabled treatments to be placed with increased sand loadings, higher pump rates, and decreased surface treating pressures. The fluid system was able to work with a variety of water conditions, including brines having more than 30,000 ppm chlorides. In one case the new fluid system allowed operations to entirely move away from gel chemistry and surface hydration equipment. The study presents measured results during the frac on one of the first applications of a high viscosity friction reducer in Marcellus shale treatment.

Friction reducers (FRs) are used to decrease the amount of horsepower required to move a hydraulic fracturing fluid through a formation at a fixed flow rate. Though FR viscosity is not a crucial consideration in proppant transport when used before the perforations in slick water applications, FR viscosity becomes a greater consideration in proppant transport from the perforations into the formation and an important qualifying criterion with the advent of High Viscosity Friction Reducer (HVFR) systems that require higher loadings than traditional FRs. Consistent viscosity measurement can vary greatly depending upon a number of factors, for example temperature, hydration approach, polymer concentration, brine composition, and additive interaction. A study was developed and implemented to determine the influence of HVFR by concentrated particulate and bead settling. This study investigated the viscosities of five HVFRs applying eight variables using response surface methodology. Initial study criteria were establishing consistent hydration with unique apparatus design and viscosity measurement verification. Once established, this method examined the effects of 1:1, 2:1, and 2:2 salts, singularly or in various concentrations and combinations. Experimental designs under fresh water conditions were also conducted with varied HVFR loadings (1.0 to 6.0gpt), blender RPM (600 to 12,000), and blender mixing times (0.5 to 8.7 minutes). Viscosities were measured from 200 to 6000 (1/sec). Static settlement testing in ranges of 0.87 to 3.50 pounds per gallon in 0 to 140,000 total dissolved solids (TDS) brines was conducted. Single bead settling measurements were performed in fresh water and API brine. Specific HVFR and salt matrix combinations tested resulted in highly correlated response surfaces exhibiting consistent trends. The TDS and hardness had a minor to major influence on viscosity based upon the specific HVFR examined. Brines were predominately antagonistic with respect to viscosity with few synergistic results. The influences of HVFR dosage and mixing correlated highly to the viscosity of all HVFRs, and extended mixing time durations had no influence on some HVFR combinations indicating a viscosity reduction limit. In certain regions of the design space, settling rates were related to viscosity. Selection of an HVFR system precisely tailored for a specific brine composition guaranteeing maximum friction reduction and proppant transportation performance was vital. The influence of pumping and tubular transport on the HVFR viscosity is continuous and quantifiable. Additionally, the viscosity of the HVFR in a downhole brine environment provides discernable data for assessing far end well bore proppant transport and damage potential. This study established a reliable method for gauging performance and examining measurable field variables of HVFR systems.

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.

Significant effort around bacteria monitoring has been a focus since July 2016. Water testing program covers all operating areas including southwestern Pennsylvania and Marshall county, West Virginia. The program began with most probable number (MPN); otherwise known as serial dilution testing, for sulfate reducing bacteria (SRB) and acid producing bacteria (APB). Based on the water test results, biocide treatments were performed for selected wells from October 2016. More than 300 horizontal wells from Marcellus formation were tested for SRB and APB by third quarter 2017 and biocide treatments were optimized by the end of 2017. Bacteria DNA testing in the form of next generation sequencing (NGS) and quantitative polymerase chain reaction (qPCR) was performed on selected wells to characterize the microbial consortium present in these samples. Due to the limitations of serial dilution testing and understanding of the bacteria makeup with DNA testing, the program has evolved to utilize fieldwide adenosine triphosphate (ATP) testing and a locked-down biocide treatment procedure. Biocide treatments are prioritized during extended midstream maintenance to minimize downtime and maximize contact time and have shown to be effective for extended durations. To investigate the root causes of bacteria, data science tools are utilized to look at the effect of the completions design and other variables on bacteria during operation. Variables under consideration include biocide type and concentration, fracturing fluid chemical additives, produced water reuse during completions, produced water chemistry, and geologic variation. Initial findings will be discussed and shared with lessons learned from production operations.

BACKGROUND A problem that many exploration and production companies face is how much impaired flowback and/or production brine can safely be reused on future completions; and what chemicals should be included in the fracturing fluid design to mitigate any concerns. The main focus will pertain to slickwater fluid designs. METHODS The authors used geochemical modeling hardware/software in combination with cuttings and sequential flowback analyses to acquire a full understanding of the shale constituents and mineralogy that disbands in formation. One can also determine the efficacy of the scale, clay, and iron control chemistries associated with the fracturing fluid design with sequential flow back analyses. Friction flow loop and rheology data confirm the homogeneity of the fracturing chemistries chosen for the application. RESULTS The data obtained from the cuttings analyses and sequential flowback studies confirm a correlation between the shale geology and flowback characteristics. This information confirms proper scale control selection and loading which will allow for a scale free formation. Microbiocide efficacy studies performed throughout the project indicate the propensity for microbiological activity and the successfulness of mitigation strategies. Friction flow loop data confirms the compatibility of the fracturing fluid constituents and the efficacy of those chemistries in stressed water conditions. CONCLUSION Studying geochemical formulary and water quality to develop a database for both well production and water quality of the producing well is critical in understanding water reuse. This data will allow the operator to make better decisions concerning optimal fracturing fluid design for slickwater application and proper reuse of water on subsequent hydraulic fracturing.

Volume and salt concentrations in Marcellus flowback water depend on geology, drilling and completions, stimulation and flowback operations. Recent studies include evaluations of geochemical origins based on the compostition concentrations, flowback sampling analysis and numerical studies. However, an in-depth understanding of chemical compositions as well as the changes of compositions is still needed. In this paper, we will first review the literature related to flowback water in Marcellus shale gas wells to fully understand the chemistry, geochemistry, and physics governing a fracture treatment, shut-in, and flowback. We will then gather all public and in-house flowback data, named as 3-week or 3-month flowback in this work, to build a data set of flowback water compositions. After data screening, we will then analyze this composition database using four different methods: geographical, changes over time, linear regression, clustering and multi-variable analysis. New understandings such as the magnitude and prevailing trends of concentrations for target constituents as well as the correlations among flowback compositions, the differentiation between early and late time flowback water were obtained and explained on the basis of geochemistry and physics. Guidelines for a comprehensive sampling protocol will be provided based on our analysis.

Friction reducers (FRs) are an important component for slickwater hydraulic fracturing applications. To continue to effectively treat multiple clusters in longer laterals, even for stages out near the toe area, a robust FR system is typically required to overcome pipe friction. Additionally, it is imperative to be able to use one single FR system throughout the entire treatment that can tolerate various water sources of varying salinity up to 300,000 ppm. This paper discusses the field trials of a new salt-tolerant FR system in the Marcellus shale. A three-well trial program was initiated in the Marcellus. Various water sources with varying salinities were used with up to 100% re-use of produced water. The operator had not been able to keep the surface treating pressure between 8,000 and 8,500 psi using a standard anionic FR, which typically resulted in a lower pumping rate of less than 100 bbl/min; the first few stages using the standard FR in these wells indicated this was the case. After switching to the new FR, however, the pumping pressure immediately dropped to below 8,500 psi and the pumping rates were increased and maintained at 100 bbl/min. This new salt-tolerant FR system consists of a water-in-oil cationic polymer and an inverter. Unlike other FRs, the distinctive advantage of the new FR is that the ratio between polymer and inverter can be readily adjusted on the fly to achieve maximum friction reduction. During the pumping operations, it was demonstrated that the inverter was sufficiently quick to invert and release the polymer from oil to water, and the cationic polymer was extremely efficient at reducing additional pipe friction, even with severely impaired water. Additionally, the use of a single FR reduces inventory stock and simplifies on location quality assurance of material usage.

This paper discusses a well-to-well spacing test on a 5 well pad in the Utica Shale that was stimulated with a unique stage sequencing plan. The stage sequencing plan provides an improved understanding of the way that fracture growth can be influenced by subsurface pressure differentials created by newly fractured, shut-in and depleted wells. Chemical (water) tracers and oil tracers were pumped into the center well of the 5 well pad. The non-traced wells on the pad, along with 2 wells on an adjacent pad, were all sampled during flowback and production. The samples were analyzed for the presence of oil and chemical tracers to determine the extent and degree of well-to-well communication. Additionally, surface microseismic data was collected and used to further assist in the study of the fracture growth. The tracer communication and microseismic data were represented together in a 3D visualization of the well pads. Generally, the tracers and microseismic events show that there is more extensive fracture growth from a treatment well to offsetting wells when there is no hydraulic pressure barrier between them. Better fracture containment and symmetry was observed on stages that were bounded on both sides by wells that were just fractured. Data from the study show that proper sequencing of the completions can mitigate the tendency for fractures to preferentially grow towards depleted wells. The study will therefore illustrate the value of tracer and microseismic data for understanding additional or new knowledge about multi-well pad stage sequencing and its role in fracture growth, and overall future well planning strategy.

Over the last several decades, the industry has generated a large amount of proppant performance data using designated API methods. However, recent studies validate that correlations and conclusions generated from standard API testing do not accurately predict ceramic proppant performance in unconventional reservoirs. This overestimate of proppant performance can have negative effects on initial well production, in addition to steepening the production decline curve. The same study suggests the modified API RP 19-C procedure for testing of proppant performance under thin layer/monolayer conditions yields results which better correlate with well production data trends. Also demonstrated in the study, the proppant pack failure mode and mechanism can be vastly different in a monolayer pack versus a multilayer pack and suggests that in order to improve well performance, operators would benefit by choosing proppants based on their ability retain fracture width under low proppant concentrations; such as 0.5 and 0.25 lb/ft 2 . The presented study expands previously mentioned work to evaluate the influence of stress cycling on the performance of various proppants in thin pack/monolayer conditions. A cycle test involves a 2,000 psi/min ramp-up to desired pressure, 2 minute hold at pressure and ramp down to 25 psi. The process then repeats to obtain the desired numbers of cycles on the proppant. The results compare the performance of proppants under a single stress cycle to samples subjected to 3 or 5 cycles. Testing is performed with sample concentrations of 4 lb/ft 2 (API standard) and 0.5 lb/ft 2 (thin layer pack) at 6,000psi. The results reveal a decrease in mechanical performance for all tested samples under 3 and 5 cycles as compared to standard 1 cycle test. Clay-based ceramic proppants and sand proppants show a significant increase in crush with an increase in number of cycles. Clay based samples appear to be especially sensitive to stress cycling under thin layer/monolayer conditions. For example, 3 cycles at 0.5 lb/ft 2 loading, the crush resistance of clay based proppants increases by close to 8%, while sand crush increases by only 6%. This high sensitivity is not present when testing is performed at 4 lb/ft 2 . Intermediate strength ceramic (ISC) proppants show the highest resistance to cyclic stress under both thick proppant pack (4 lb/ft 2 ) and thin proppant pack (0.5 lb/ft 2 ) conditions. Paper quantifies the effect of reduced fracture thickness and stress cycling on performance of different proppant types. This study further discusses advantages and limitations of designed of used method as compared to common API procedures.

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.

This paper discusses design considerations to increase the estimated ultimate recovery (EUR) on underperforming wells in a refracturing scenario. A method for, and case histories of, using an environmentally acceptable, self-removing particulate diverter that has proven to be successful in the refracturing efforts of horizontal unconventional reservoirs are provided. This method is typically chosen for its low cost, self-assembly, and self-removal. An outline of the design process for refracturing and post-refracturing procedures is included. The ability to add reservoir contact, restore conductivity, remediate blockage, and address depleted reservoir pressure make this technique desirable. Different strategies can be applied when using this technique and are typically customized to the particular candidate well selected for the refracturing treatment. The treatment designs for the wells discussed in this paper were designed to increase EUR. Candidate wells for refracturing typically fall into one or more categories: understimulation occurred in the original completion, production damaging mechanisms are present, a low investment lease retention strategy was originally required, or a pressure-sink mitigation strategy is necessary for infill completions. Candidates in this paper fall into the understimulated category. A typical procedure consists of casing inspection, wellbore cleanout, possible addition of perforations, and flowback considerations. In this study, different Haynesville shale refracturing treatments, results, and diagnostics are compared. The evolution of treatment design components, such as carrier fluid, fluid volume, proppant volume, and diverting methodology, is explained. The results and underlying theory of these changes are outlined. Pre/post-treatment production is compared, along with treatment pressure trend analysis and microseismic data. Although performing secondary stimulation treatments is becoming more common, the industry's focus on improving production decline curves has led to a surging interest in refracturing horizontal unconventional reservoirs. Decline rates in unconventional reservoirs tend to be more rapid compared to conventional reservoirs because of their ultralow permeability, limited reservoir contact, and original completion strategy. Refracturing of these reservoirs enables the recovery of hydrocarbons trapped by these restrictions.

As longer laterals are drilled in the Utica to maximize acreage cover, the stimulation treatments must still establish high pumping rates to effectively treat multiple clusters even within the stages out near the toe area of the lateral. Overcoming this additional pipe friction as well as using various water sources of varying salinity (up to and including 300,000 ppm) with only one friction reducer (FR) polymer product is now possible. An additional benefit of this new salt-tolerant polymer (STP) as the FR additive is its ability to self-degrade with time and temperature to provide significant viscosity reduction for improving well cleanup after the treatment. This paper discusses use of this new STP to successfully place 131 stages in the Utica on a three-well pad in Ohio using various percentages of brine water with the freshwater supply. This is contrasted with traditional FR and guar used in 61 stages on the same pad and 39 stages on an offset pad. The ability to continue operations in the subfreezing temperatures of winter, coupled with the ability to reuse produced water, provides additional benefits to field operations. The use of a single component STP as the friction reduction provider also reduces inventory stock and simplifies on-location quality assurance of material usage. Analytical production simulation confirms improvement in productivity index (PI) and estimated ultimate recovery (EUR) forecast.

Knowledge of water-rock interactions on the surface of fractures is important to develop an understanding of the geological structures and changes within the formation, to determine the water pollutants in produced water during hydraulic fracturing, and to manage effectively the produced waters. To obtain this knowledge, the water-shale interaction is investigated on carbonate-rich (Eagle Ford), organic-rich (Green River), clay-rich (Barnett), and other minerals rich (Marcellus) shale samples. Crushed shale samples were exposed to water for three weeks at reservoir conditions. The water and rock samples before and after each static experiment subjected to several analyses. The change in the rock mineralogy was defined with XRD, the elemental composition of rock was determined with XPS and SEM-EDS. The water was analyzed for its anions and cations, total dissolved solids (TDS), conductivity, pH, total organic carbon (TOC), and average particle sizes of colloids. The stability of the colloids are characterized with Zeta potential. It has been observed that Barnett rock is high in illite content, the greatest calcite concentration is determined for Eagle Ford rock. The sulfate source of water correlates with the atomic percent of the sulfur and oxygen elements determined through XPS analyses. The magnesium content of water correlates mainly with illite amount in the rock and calcium concentration associates with the calcite and gypsum content of the rock samples. The greatest dissolution rate belongs to the minerals which yields sulfate in the water, then, gypsum and calcite which yield calcium cation in the water come second, and the lowest dissolution rates obtained from the magnesium containing minerals mainly dolomite. TDS of the water samples shows that Green River has the least tendency to interact with water and Barnett has the greatest tendency. Zeta potential values indicate that the particles in the water interacted with Eagle Ford have the highest tendency for precipitation, since it has the lowest zeta potential value. This study provides correlations on water-rock interaction for four different shale samples. These correlations can be used to understand the water-rock interactions for different rocks by conducting simple XRD and XPS measurements only on rock samples.

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.

Hydraulic fracturing has increased immensely in recent years. An accurate prediction of frictional pressure losses of fracturing slurries is crucial for successful treatment and to avoid premature screen-out or even treatment failure. Scarce data and lack of theoretical basis of slurry flow, especially in coiled tubing has led to very limited number of correlations that are available to predict slurry frictional pressure losses. Yet, the accuracy of the available correlations is still questionable. The current paper presents a statistical comparative analysis of the available frictional pressure losses correlations for slurry flow in straight and coiled tubing employing the recently introduced math modeling technique that gives weight for the models known as Akaike information criterion, AIC. With the help of AIC, the authors evaluated the available correlations to examine their accuracy. The results show that none of the available correlations can accurately predict friction pressure losses of slurries. The correlations show some reasonable accuracy within a very limited data range. However, they fail outside this range indicative of their poor applicability. AIC shows how much information is lost when using these correlations which can lead to erroneous results, and even job failure. This fact keeps the gates widely opened for more in-depth experimental, analytical, and theoretical analysis for better understanding of flow behavior of fracturing slurries aiming at developing a more realistic correlation to predict their frictional pressure losses. This paper represents the authors' first step toward developing such correlation, with the application of information theory and AIC.

For some time now the industry has been concentrating on horizontal wells in shale formations which require multi-stage fracturing operations to tap their production potential. Several different techniques have been developed for performing these operations each with their own advantages and drawbacks; however, when it comes to performing re-fracs the isolation of zones to be treated presents some major problems in logistics and operating costs no matter the initial fracturing operation method used. A key characteristic in unconventional reservoirs development is that they need massive hydraulic fracturing to create high permeability conduits to connect the reservoir to the wellbore and assure appropriate flow rates to make the development economical. In general, production performance for this type of reservoirs show an early high inflow followed by a steep decline. Refracture jobs have been a common practice to mitigate the flow rate decline and revitalize wells productivity. In the cases where infill refracturing is used, the isolation of the existing perforations is imperative, to mitigate the loss of fluids during the refracturing process. One approach involves the use of mechanical diverters, such as perforation balls, rock salts etc., which may be useful for one stage; however, cessation of pumping operations results in them falling out of the perforations or dissolving. In this paper, a new approach is presented using degradable materials. These materials can be tailored to plug perforations on a temporary basis but degrade over time, depending on formation temperature, to re-open them. This method has applications in initial fracturing operations as an alternative to the often used "plug and perf." method and can be extremely advantageous in refracturing operations in plugging off the existing, productive perforations and exposing the unproductive ones for treatment. It also provides similar advantages in wells with existing perforations, where additional perforations are added and need to be treated. Moreover, a case study is used to show the application of these degradable materials in a refracturing job in a shale gas well in the Marcellus Shale. Based on the results, the sealing agents successfully bridged off the existing perforations, diverting the refracturing fluid to the new clusters. In this paper the author will discuss the evolution of fracturing methods and describe the development of degradable materials which can degrade over time for a range of bottom hole temperatures. He will continue to present a case study of its' use in a refracturing treatment in a well with 26 sets of existing perforations and 24 sets of recently perforated clusters, with the intent to seal the older clusters and begin accessing the new clusters.

Acidizing as a stimulation technique does not always yield the desired sustainable conductivity especially compared to hydraulic fracturing. In addition to that, hydraulic fracturing provides a great contact with shale formations due to its deeper developed conductivity that is sustained by the existence of proppant. However, hydraulic fracture conductivity declines because of a variety of reasons: increasing effective stress, proppant fatigue due to stress cycling, and digenesis. Here, we studied the potential of combining the benefits of propped hydraulic fracturing and acidizing by introducing low concentrations of acid slugs in the hydraulic fracture treatment of shale formations. The acid slugs intended to improve the micro-fracture conductivity deep in the formation and near the wellbore. Experiments using low concentrations of HCl (up to 3 wt% active HCl) showed a great enhancement in oil recovery factors and shale porosity. The treatment was carried out at 200°F. Furthermore, the effect of the HCl treatment on samples from Mancos, Eagle Ford, Barnett, and Marcellus shale formations was examined. The samples used were 2.54-3.81 cm in diameter and 0.76-5.08 cm in length. The porosity measurements on the cores before the treatment range from 0.23-7.7% versus 0.2-35.8% after the treatment. Spontaneous imbibitions showed recovery factors of 2.5-13% from non-treated samples against 4-53% from the treated samples. The treated samples were saturated with more oil compared to the non-treated samples due to the improvement in porosity and permeability by the acid treatment. CT scan images also have been taken for the samples pre and post the acid treatments to show the effect of the treatment on the porosity and cracks distribution along the cores. Our study clearly demonstrates that injecting slugs of low concentrations of HCl near and away from the wellbore adds permanent improved conductivity to hydraulic fracturing that is resulted from the partial dissolution of calcite.

Oil and gas-bearing shale formations have received a great deal of interest in recent years, especially in North America. Oil and gas from shale could make a significant contribution to global hydrocarbon production. However, their development has been hindered by the complexity of drilling and completion strategies, which must be adapted in response to shale's mineralogy and physical properties. Matrix acidizing is commonly used as a pre-flush to the hydraulic fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons. In some plays it is used as the main stimulation technique (e.g. Monterey shale, California). In this paper, the mineralogical and physical responses to matrix acidizing of several important North American shale formations were evaluated, and the effects on their physical properties are described. Samples of Eagle Ford, Mancos, Barnett and Marcellus shale formations were exposed to different concentrations of HCl (1-3 wt%). Based on experimental observations, mass loss, and X-ray diffraction studies, the samples lost as much as 16 wt. % calcite when treated with 3 wt% of HCl for three hours. Post-reaction measurements show increases in porosity in all experiments, which was attributed to calcite dissolution in Eagle Ford samples and to crack development in Mancos, Barnett, and Marcellus samples. Eagle Ford samples showed the greatest reduction in Young's Modulus ranging from 25-82% when exposed to 1-3 wt% HCl solutions and 75% when exposed to 5 wt% NaCl saline solution at 200°F.