Guar and its derivatives, hydroxyl propyl Guar (HPG), carboxy methyl propyl Guar (CMPG), are currently the major gelling agents used for fracturing. However, there is the problem of insoluble residues in Guar after gel breaks. Such residues cause formation damage and low conductivity. Conventional cellulose fluid has problems such as difficult preparation, low temperature limit and high formation damage. This paper presents a novel cellulose derivative of low molecular weight, instant dissolution and free from residue. The new cellulose has better hydrophilic and thickening properties through chemical modification of its structure. The strong hydrogen bonding in cellulose is reduced by alkalization and etherification of substituent group. The viscosity of the new cellulose at 1% (w/v) is 505 mPa·s while the viscosity of HPG or CMPG is 280~320 mPa·s. Its molecular weight is 6×10 5 , which is 1/4 Guar. An organometallic crosslinker was also developed for the new cellulose. Fluid was crosslinked at pH 5-7. Its upper temperature limit was 158 °C. The viscosity of fluid remained 75 mPa·s for 120 minutes at 170 S -1 while that of broken fluid decreased to 1.76mPa·s. No residue was found after the gel was broken, and its conductivity improved. Formation damage is less than 13% in the core test. The new fluid was tested in 18 wells in the tight gas and oil reservoir in western China. Results showed that the new fluid was easy to prepare and rapidly dissolved with no "fish eye". The crosslink of the fluid can be delayed. It has excellent properties of proppant suspension. Oil production after stimulation using the new fluid increased 2-5 times compared with wells in similar locations. Gas production in multiple wells of the tight gas reservoir increased to 1.78×10 5 m 3 /d after stimulation with the new fluid, 3.38 times higher than similar groups of wells using Guar as stimulation.

Optimization of conductive fracture area is perhaps the most critical tenets of fracture stimulation. Several attempts have been implemented to improve the effective fracture area, such as hybrid fracturing, ultra-lightweight proppant (ULWP) delivery, channel fracturing, and slug fracturing. The techniques are all based on viscosity-governed proppant transport mechanisms. This paper presents a new fluid system, based on packing of soft particles, for nearly perfect proppant suspension to improve proppant transport and vertical distribution in fractures. Proppant particles are trapped in the "void" space created by particles packing against each other, and the mechanism is completely different from that of conventional fracturing fluids. It improves effective fracture height by placing proppant across the complete productive interval under downhole conditions when properly applied. This leads to better transverse and vertical placement of proppant in the fracture and significantly increases the fractured surface area. The fluid was tested extensively in conventional fracturing fluid protocols to confirm its feasibility because, mechanistically, it works completely different from conventional fluids. Hydration tests show that the hydration rate can be tuned to maintain the particle integrity during fracturing treatment. HPHT rheology tests show that the fluid is compatible with conventional fluid additives. Static proppant settling tests show superior proppant suspension capabilities. The fluid can be decomposed with live and encapsulated oxidizer breakers to meet treatment design requirement. The fluid can be completely cleaned up and regained proppant pack conductivity was close to unity. Interesting fluid behavior was observed during large scale slot cell testing at room temperature. The fluid was successfully applied in the Cotton Valley and it was confirmed that the novel fluid can be smoothly pumped through fracturing equipment and it also offers several operational benefits. Criteria and considerations for successful application of such fluids to optimize proppant placement and maximize fracture conductivity are discussed. Job design is elaborated in terms of fluid mechanics and proppant transportation mechanics differences and benefits over traditional crosslinked gel systems. The execution, experiences, and subsequent well performance of treatment applications results are compared to offsets treated with a traditional crosslinked gel system.

The development of a high-temperature seawater-based fracturing fluid has received much attention because it offers a solution to fresh water shortages; however, the rheological properties suffer significantly as a result of interactions between dissolved ions with fluid components. Various strategies have been investigated to address this challenge, including seawater treatments that ultimately remove the highly soluble and insoluble ionic moieties to yield a fracturing fluid with reliable rheological characteristics. Most polymer-based fracturing fluids have limited salt tolerance. Interactions between the polymer and divalent cations in seawater inhibit proper polymer hydration, thus preventing generation of an elastic polymer network and potentially affecting the crosslinking mechanism. In this study, concentrations of critical ions in seawater were reduced using a reliable seawater treatment. This treatment allowed a reliable fluid at higher temperatures and also considerably reduced the scaling tendency of the fluid. The fluid presented herein, designed in the treated seawater, yields a stable elastic polymer network when used in conjunction with stabilizing additives and is capable of effectively delivering proppant down hole. This newly developed formulation uses a combination of instant and delayed crosslinkers and additional stabilizing additives required at optimum concentrations to yield a stable fluid system in the treated seawater. At high temperatures, the addition of typical ion sequestration agents failed to eliminate the negative interaction between dissolved ions and fluid stability, thus requiring water pre-treatment. The fluid system exhibits reliable rheological properties and yields a clean broken fluid for excellent proppant pack cleanup in high total dissolved solids (TDS) waters up to 350°F. Typical guar-based fracturing fluids require a high pH (greater than 10) to maintain rheological stability at high temperatures. The fracturing fluid presented herein was developed at pH 9 in treated seawater and maintained its elasticity and viscosity over a long period of time at temperatures up to 350°F. An added benefit of controlling the pH and not surpassing pH 9.5 was also revealed—scale control. This study discusses the development of a new seawater-based fracturing fluid for use in high-temperature wells. This can result in a paradigm shift in source water use for hydraulic fracturing.

Hydraulic fracturing is the primary completion method in the unconventional Sohagpur Block coal seam gas (CSG) project targeted at low to high-volatile bituminous Barakar coal seams. Each well contains up to four to six seams with an aggregate thickness of 6 to 32 m and depths ranging from 400 to 800 m. The coal seams are mostly comprised of naturally fractured material (butt and face cleats) with very unique geomechanical properties, which poses many challenges in terms of coal stimulation. The coal is inherently prone to creating multiple fractures during hydraulic fracturing stimulation treatments, including T-shaped, parallel, or branched fractures. Commonly, during multiple seam stimulation, the probability of complex fracturing increases dramatically. The higher value of pressure-dependent leakoff tendency and high process zone stress (PZS) leads to higher treating pressures (relative to depth) during fracturing treatment, which, in turn, normally causes breakout into and possibly through the lower stress boundary zones. Poor proppant placement and inconsistent areal proppant distribution leads to minimized proppant pack conductivity and ultimately productivity loss. As a result, the hydraulic fracturing treatment options dwindle significantly, thus reservoir stimulation results are not optimum in each seam. During the CSG unconventional stimulation case discussed in this paper, the determination of fracture height and proppant pack quality was of the utmost importance. To evaluate fracture height and proppant pack quality and minimize complex fracturing growth and breakouts, a unique and environmentally acceptable high thermal neutron capture compound (HTNCC)-coated proppant technology was adopted for the first time in this CSG basin in India. The new proppant system was pumped during multiple seam stimulations to verify the post-fracture analysis of the coal seam observed using a three dimensional (3D) planar numerical model. The results were then used to sensitize fluid systems and volumes and tune proppant volumes with optimum treatment pumping rates against the standard "cookie cutter" method of 4,000 lbf/ft of coal. The normally observed extensive height growth and proppant distribution was then re-evaluated during the next interval treatment. The application of this nonradioactive (RA) tracer technology has resulted in achieving increased effective fracture length of each individual seam, increased proppant conductivity, and significant fracturing pressure drop during the treatment execution. Overall, this technology has greatly helped the development of effective coal seam fracturing design and validation. Selection of the correct diagnostics has helped improve the understanding of some of the significant questions remaining in regard to unconventional CSG basins. This paper discusses the lessons learned to achieve optimized seam completion design and verified results, which can be applied in other CSG basins.

Petroleum exploration and production from Bakken and Three Forks formations in Williston Basin have achieved great momentum since 2005. To overcome the resistance of the low to extremely low permeability to hydrocarbons flow from reservoir to bottomhole, horizontal wells with multistage fracturing completion are applied to gain economical rate. Currently, horizontal lateral lengths that exceed 10,000 feet with more than 50 stages are not uncommon in Williston Basin. Field experience and practice indicate that different stage intervals usually results in different estimated ultimate recovery (EUR). Therefore, it is worth to identify optimal stage interval to stimulate horizontal lateral to cut costs through using the appropriate volumes of fracing fluid and proppant and to maximize profit by improving EUR. It should be noted that production from horizontal well with multistage fracturing is not only impacted by several factors such as geological characteristics, lateral length, orientation of horizontal lateral, fracing fluid, proppant, stimulation operating and procedure, and fracturing stage interval, but also by their interactions. To make the analysis reasonable, normalization analysis is exploited to differentiate the influences of different parameters. Sensitivity analysis of individual variable is applied to evaluate its influence on production. The analyses give a range of optimal stage interval for Bakken and Three Forks formations in different fields in Williston Basin. Considering the fact that variations in geology lead to different optimal stage intervals, it is appropriate to use a range instead of a single number as a reference in the well design. Although the results are derived from Bakken and Three Forks formations, the findings in this study can be employed in reservoirs with similar geological characteristics and reservoir properties. This study also identifies optimal ranges for operational parameters such as treatment pressure gradient, pumping rate, sand-to-water ratio, fracing fluid volume/length, and proppant mass/length, which are crucial to the cost reduction and operation efficiency.

Liquid CO 2 fracturing is a novel stimulation technology, which helps realize multiple objectives such as conservation of water, sequestration of greenhouse gases and enhancement of single-well productivity and ultimate recovery. During operations, CO 2 flows through storage tank, booster pump, blender, fracturing pump, and eventually into wellbore and production zone, generating a changing temperature and pressure distribution. CO 2 ‘s phase state, density and viscosity properties change consequently, which influence significantly the reliability and stimulation effect. In a liquid CO 2 fracturing field test for tight oil, temperature and pressure sensors are positioned at 12 critical nodes (including booster pump, blender, fracturing pump, wellhead and bottom hole) to monitor CO 2 fluid. To ensure the reliability, CO 2 is required to maintain in liquid state both on the surface and subsurface. Inlet, inside and outlet pressure of the blender should be concerned, because the blender utilizes non-mechanical pump, which requires sufficient motive flow to draw proppants into the main pipe, while the pressure difference directly impacts the flow rate of motive flow. The field test is successfully implemented with satisfactory result, 21 m 3 proppants are added into the formation. The main conclusions are as follow. (1) In low-pressure fluid feeding stage, partial CO 2 is gasified, which influences the stability of fluid feeding; In future a buffer vessel will be placed between storage tanks and booster pumps, which will provide adjustment for phase control; And a heat exchanger may help by further reduce the temperature of CO 2 .(2) Pressure difference among inlet, inside and outlet pressure of blender fluctuates during the whole process, with the probable reason of two additional static mixers, which create system pressure drop. (3) The temperature of CO 2 is very low in low-pressure stage, and the pipes are frosted; When pumping pressure reaches 38MPa, the temperature gradually exceeds 0°C, and the pipes are defrosted. Phase evolution during liquid CO 2 fracturing has been identified, and phase control method has been determined. This helps improvethe stability of fluid feeding and sand adding, and enhances the success ratio and stimulation result of fracturing.

Liquid carbon dioxide (CO 2 ) fracturing technology is one of the waterless fracturing technologies. It has the advantages of avoiding the use of water, reducing damage, and increasing production by improving the reservoir pressure. However, the low viscosity of liquid CO 2 and the difficulty to pump proppant are the main technical challenges. No conventional thickening agent can provide the required thickening used in 100% liquid CO 2 . In this paper, the problem of thickening gelled liquid CO 2 has been solved by developing a new surfactant and thickening agent. Surface active agent can make the liquid CO 2 gel by forming wormlike micelle or cylinder micelles structure. The cylinder micelles enhance the viscosity through entanglement inter-actions above a critical concentration. Rheology and friction properties of liquid CO 2 gel are evaluated through high pressure pipeline rheological experimental device. The viscosity of liquid CO 2 gel fluid changes under different pressures (10 to 20MPa), temperatures (0 to 100 °C)and different shear rates. The experiment result shows that the effective viscosity of liquid CO 2 gel fluid is between 7.654 ~ 20.012mPa.s. The liquid CO 2 was thickening with viscosity increase at 86 to 498 times under the same conditions. The field application of the new liquid CO 2 based gel fracturing fluid in two wells of Jilin oil field in China shows that the production has been increased over 100%. 19.8 m 3 of proppant has been successfully pumped to the reservoir in one well, and the mean proppant concentration is 6.8%. Liquid CO 2 based gel fracturing fluid provides a new fracturing system with less formation damage to fracturing operation. This paper will be beneficial to all engineers and technologists who are currently working at waterless fracturing applications.

The pay zone of Sulige gas field is the most typical tight sandstone rservior in China. In recent years, multi-stage completion practices of vertiacal and horizontal wells brought about significant enhancement of single well production rate and economic benefit and caused a sharp increase of water consumption as well. Currently guar-based polymers are largely used in fracturing operations in Sulige gas wells. The system exhibit good rheological properties on one hand, and it can not meet the requirement of water saving, environmental protection and factory fracturing mode on the other due to its tendency to degrade, complex disposal and high cost. As a response, a low-cost recyclable fracturing fluid is developed and tried for the gas field. A polyacrylamide polymer with surface activity is synthesized based on the consideration of reservoir characteristics, requirements in fracturing and well pad situation. The polymer and alkyl sulfonate surfactant additive formed a reversible structure in water by the action between hydrogen bonds and molecular chains. The fluid provides a good viscoelastic behavior and can meet the needs of fracturing treatment. It can be broken upon contact with formation fluid and rock minerals without destroying the molecular structure of the polymer. The flowback fluid can regain the viscoelasticity and be reused after simple settling and adding in proper dosage of the polymer. Lab experiment shows that the novel fluid has good temperature/shear resistance and excellent proppant transport capability. It is also easy to be cleaned up without leaving residue. Moreover, the performance of the recycled fracturing fluid can reach the level of that of prepared with fresh water. From 2014 to 2015, the recyclable fluid has been applied successfully in 230 wells in Sulige with a total volume of approximate 1,000,000 m 3 . The recovered flowback fluid is 400,000 m 3 , of which 380,000 m 3 was reused. The recycling rate is as high as 95%. The fluid can meet the needs for continuous-mixing and low friction during treatment. The flowback fluid is also easier and less costly to be recycled in comparasion to guar gel fracs. These advantages promise its wide adaptability.

Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This minimizes or even eliminates costly vessel trips that are necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and the results of successful field applications. This seawater-based fluid uses a low-residue polymer crosslinked with zirconium having a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Two sidetrack wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Well B comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages. The seawater-based fracturing fluid was not expected to generate damaging effects on reservoir productivity. During development, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m 3 . The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m 3 . The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, which demonstrates the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine. Eleven hydraulic fracturing operations were designed and executed successfully in both horizontal sidetrack wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m 3 in the tail stage. A total of 851 tonnes of proppant was pumped in 3156-m 3 crosslinked fluid. The seawater-based fluid properties present an innovative approach to address the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).

Proppants are placed in fractures to provide highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. Hydraulic fracturing technology is constantly improving to achieve better production performance. Ultra-lightweight (ULW) proppants are one of the technologies introduced to improve fracturing effectiveness. Compared to sand, ULW proppants can be carried farther and distributed more evenly within fractures, resulting in more propped fracture area. This paper evaluates the impact of ULW proppants on production performance in tight reservoirs and examines characteristics of formations where ULW proppants are most beneficial. To explore the advantages of ULW, hydraulic fracture models are developed. These models help in understanding the fracture geometric properties. This information is then incorporated into reservoir production models to evaluate the impact on production performance. Fractures using ULW proppants and the resulting well productivity are compared to those using sand. No technology provides a solution for all situations, and neither do ULW proppants. To better understand if ULW proppants bring the most benefit for production performance, data-mining techniques were used to identify ULW proppant field applications. Results showed that ULW proppants had better vertical distribution within the fractures than sand (sand had a tendency to settle to the lower part of fractures, leaving the upper part unpropped). In a thick reservoir formation with insufficient vertical conductivity, fractures created by ULW proppants connected larger volumes of rock, leading to higher well productivity and increased EUR. This study discusses the benefits that ULW proppants can bring to unconventional producers and identifies potential candidate formations where ULW proppant may be very effective. Field cases are included to show the benefits of ULW and the circumstances where they can bring the most value.

High-pH, guar-based fluids are favored in fracturing treatments for their low cost, ability to recover viscosity after mechanical shearing, and favorable environmental properties. Seawater can be considered as the base fluid when fresh water availability is limited. However, seawater presents a technical challenge for such fluids due to copious precipitation at high pH. The goal of this study is to find additives that control divalent cation precipitation to enable a seawater-based borate fracturing fluid suitable for high-temperature application, ideally with the additional benefit of long-term scale control. Complete sequestration of cations with stoichiometric amounts of citrate or EDTA is not economically or logistically feasible. Instead, a crystal modifier approach was adapted to control precipitation of divalent cations, especially Mg 2+ . An additive has been identified to prevent precipitation of divalent cations at high pH, as required for high-temperature borate fluids. Fluids with this additive perform as well as those formulated in fresh water. The new technology further minimizes long-term scaling risks of divalent cations in the fluids in conjunction with formation water. Conventionally, medium pH was achieved with amines to avoid severe precipitation of divalent cations in seawater. As a result, such approach is only used in relatively low-temperature applications. Low-pH fluids do not function well at high temperatures due to facile acidic hydrolysis. A versatile additive, capable of controlling divalent cation precipitation and providing long-term scale control, has been identified. Compared to citrate, EDTA salts, and other commercial additives, the new additive shows superior divalent cation precipitation control capability in seawater even at high pH, at significantly lower concentrations in lab bottle tests. Borate fluids prepared in seawater with the new additive showed excellent rheological properties at temperatures above 300°F on a Chandler 5550 HPHT rheometer. The additive is compatible with fluid additives and is easy to apply. Dynamic tubing-blocking tests showed that this chemical is also highly effective in controlling anhydrite scale in seawater-based fluid mixed with formation water that contains more than 20,000 ppm of calcium scaling ions. Proppant conductivity testing confirmed the fluid can be effectively cleaned up, leaving minimal proppant pack damage. This additive offers the most economical solution to formulating fracturing fluids with seawater and with minimal scale risk. The study presents a new additive that meets both technical and economic requirements to enable effective high-temperature hydraulic fracturing and minimizing scale risks in areas where adequate fresh water is not readily available or is limited by environmental regulations. Rheology, conductivity, and tubing-blocking test results demonstrate that seawater can be used as a base fluid for fracturing treatments in high temperature, by effectively controlling divalent precipitation approach which also offers a longer-term advantage of scale control.

After dozens of exploration and appraisal wells were drilled, fractured and tested in the Lower Silurian Long Ma Xi (hereafter referred to as LMX) shale formation in Sichuan basin since 2009, several blocks have now entered into the development phase. Hydraulic fracturing stimulation is vital to the performance of shale gas wells as well as the economics since it represents about half of the total well cost. Aiming at increasing production, most operators focus on enlarging Stimulated Rock Volume (SRV), a common means for which is to increase the injected fluid volume. Whilst injecting more fluid will lead to an enhanced SRV during the fracture stimulation process, how much of it is effective SRV under closure stress is often unknown and tends to be field specific. It is possible that a large portion of the injected fluid and consumed energy is actually ineffective in terms of adding more production rate. Based on some early production data of wells in Fushun-Yongchuan (herein after refer to as Fushun) block and its sensitivity analysis to completion parameters, it is found that the amount of injected fluid volume does not obviously impact the performance. Instead, proppant intensity; the volume of 100 mesh natural sand carried by slick water; and proppant pack continuity are all more important variables. These variables are not generally the focus of most operators in the area. A concept for improving the effective or propped SRV is developed as a result, with key points summarized as below: Significantly reduced frac fluid volume compared to original base design; Enhanced proppant intensity; Significantly increased 100 mesh sand volume; Continuously adding proppant to achieve best proppant pack continuity at fracture face; Tailored frac fluid design to meet the proppant transportation needs meanwhile minimize the residue damage The above concept has been put into field trials in Fushun area. Field execution went well and demonstrated higher efficiency in terms of operation time, however did require a higher level of onsite QAQC and real-time engineering control. Early production data has been gathered and analyzed to assess the performance impact of this approach, indicating that a consistent performance improvement has been observed. This new shale gas frac concept is practical and beneficial on both operational efficiency and well stimulation performance.

Hydraulic fracturing is a very robust tool in terms of not only increasing production in tight reservoirs but also accelerating production from reservoirs with higher permeability and porosity. The success of a hydraulic fracturing treatment is highly correlated with control of the created fracture geometry. Control of fracture growth and geometry is challenging in formations where the boundary lithologies are not highly stressed compared to the pay zone, allowing out-of-zone migration of fractures. As several factors influence the growth and geometry of fractures, including the reservoir, wellbore, and fluid/proppant parameters, it requires a good understanding of reservoir parameters, including stress distribution along with appropriate use of corresponding wellbore components and fluid/proppant for successful and efficient results. Our objective is to outline the main differences between different fracture models along with the key parameters and their significance in fracture performance. Fracture treatment designs involve selecting fracturing fluids, additives, proppant materials, injection rate, pump schedule, and fracture dimensions. Although hydraulic fracturing has become more important due to development of unconventional resources in tight formations, the use of fracture models before implementation of the treatment is limited, leading to undesired fractures either with limited growth or propagation out of zone. Literature lacks a study that combines the evaluation of different fracture models in an optimization process where economics is taken into account with an objective function maximizing the net present value (NPV), providing detailed information on the financial side of this technical phenomenon, too. In this study, different numerical fracture models are used to design the fractures in a tight oil reservoir, the performance of designed fractures are analyzed to measure the success of different numerical models applied in design along with an overview of critical operational parameters together with the significance of parameters, including size, number, and location, phasing angle of perforations, fluid and proppant type, rock strength, porosity, and permeability on fracture design optimization‥ In our paper, a comprehensive literature review of previous studies on tight oil reservoirs and hydraulic fracturing provides a thorough theoretical comparison of fracture models used in oil industry along with the analysis of significance of each factor throughout the process of hydraulic fracturing tight oil reservoirs. An objective function that maximizes NPV is used in this study investigating the phenomenon not only from the physical but also the economical aspects of fracturing that is still an expensive but an effective way of production enhancement technique when applied wisely.

Experimental measurements of the fracture conductivity and rock mechanical properties are presented for the five different geological facies of the Eagle Ford shale (A, B, C, D and E) as defined by Donovan el al. (2012 ). In this classification, facies A lies right above the Buda limestone, followed by facies B which has the highest total organic content and production. This study places emphasis in this zone. Facies A and B are known as the lower Eagle Ford shale, whereas facies C, D and E are known as the upper Eagle Ford shale. Facies E underlies the Austin chalk. Conductivity samples in three orientations and core plugs in two orientations were obtained from outcrops samples. The orientations represent vertical fractures with flow in the horizontal direction (X0 orientation) or flow in the vertical direction (X90 orientation), and horizontal fractures with horizontal flow (Z orientation). Short term fracture conductivity experiments were performed using a modified API conductivity cell at room temperature. Unpropped and propped conductivities were measured with gas flow. Low proppant concentration was used in order to simulate a slick-water treatment. Proppants of various sizes were placed manually on a rough fracture face. The fracture faces were scanned with a surface profilometer to calculate the fracture roughness. Compressive triaxial tests were performed on the core plugs in order to determine the elastic rock properties such as Young's Modulus and Poisson's Ratio. Additionally, Brinell hardness tests were completed to determine the resistance to embedment. Mineral composition was acquired by X-ray Diffraction analysis. The obtained fracture conductivities were compared to the fracture face roughness, elastic mechanical properties, Brinell hardness and mineralogy of the samples. It was found that propped and unpropped conductivities decline exponentially with closure stress. Propped conductivity was found to be dominated by proppant characteristics. Conductivity is positively related to rock brittleness and inversely related to Poisson's ratio. For the samples cut perpendicular to the bedding, no significant difference was found for between horizontal flow (X0) and vertical flow (X90). The parallel-bedding samples (Z) in general have lower conductivity compared with the perpendicular-bedding (both X0 and X90). Within facies B, samples with flow on the bedding plane (Z) were found to have the lowest conductivity. The findings of this study provide useful information to understand the outcomes of fracture stimulation in Eagle Ford, and therefore to assist fracture treatment design.

With the increase in demand for energy, natural gas from tight reservoirs is being targeted abundantly around the globe by different operators using hydraulic fracture technology. Reducing the environmental footprint associated with hydraulic fracturing is a priority in optimizing this technology. An environment friendly, polymer-free fracturing fluid has shown remarkably consistent results, following multiple deployments in Saudi Arabian tight gas formations. Alongside laboratory tests, field studies such as fracture geometry and conductivity, ecological impact and well productivity were investigated over several wells targeting the same formation. The main objective was to test the field performance consistency of the fluid. Also, integrated post treatment results were collected as case histories for comparison to offset wells. Flowback data indicated significant reduction in fracture cleanup time with 95% retrieved fluids compared to 40-60% in polymer-based fluid. Therefore, improvement in early production response was noticed due to higher retained permeability and proppant pack was left damage-free due to minimal residue left inside the formation. The post treatment reports indicated improved fracture conductivity and geometry containment in the pay zone compared to offset wells that used conventional polymer-based fluids. Additionally, because of its enhanced viscoelastic nature, the fluid system exhibited excellent proppant transport capacity at low viscosity without compromising fracture half length. The environmentally friendly surfactant-based fracturing fluid demonstrated superior performance in tight sand formations of Saudi Arabia, especially while stimulating zones in close proximity to water zones where contamination must be prevented. This paper will also discuss the potential of further development to this fluid such as improving its overall efficiency that could mark future technological advances in the petroleum industry.

The success of fracture stimulations depends on the ability to fracture the rock and to maintain fracture conductivity. Therefore, in order to have a successful treatment, the effect of rock and proppant characteristics should be understood. This paper investigates the relationship between fracture conductivity and rock properties for two different locations in the Marcellus shale. In this work, a series of experiments were performed in order to better understand the mechanical behavior of the Marcellus Shale. Multiple cores from Allenwood and Elimsport locations in Pennsylvania were collected to ensure repeatability in the results. The core samples were cut parallel and perpendicular to the bedding planes in order to analyze the effect of anisotropy in fracture conductivity. Additionally, compressive triaxial tests were performed to obtain the rock mechanical properties such as Young's Modulus, Poisson's Ratio and Ultimate Compressive Strength, and X-ray Diffraction analysis was used to obtain mineralogy composition. The laboratory results were carefully compared with previous fracture conductivity data and surface roughness data from the same Marcellus shale locations where proppant concentration was kept constant to reduce the variables affecting the fracture conductivity behavior. The findings showed that the anisotropy effect is present for this formation and reflected in the fracture conductivity values, where samples parallel to the bedding plane seem to have higher Young's Modulus. It was confirmed that at proppant monolayer concentration the main mechanism for conductivity loss is proppant embedment, where due to the high localized stress, the rock-proppant interaction goes directly to permanent deformation of the rock. It was also observed that a higher Young's Modulus helps to maintain the fracture width which translates in lower rate of conductivity loss with increasing closure stress, therefore, rock mechanical properties have impact on fracture conductivity. The phenomenon observed is less pronounced if a multilayer proppant concentration is used, where the proppant pack characteristics become an important parameter in fracture conductivity. In this paper, we present an analysis of the effect of rock properties in the fracture conductivity behavior based on a series of experimental results from the Marcellus Shale, where the role of permanent deformation was taken into consideration as a parameter causing fracture conductivity lost. This is the first time the effect of rock characteristics in fracture conductivity is analyzed based on experimental work for the Marcellus shale.

Egypt's Western Desert contains a series of basins underlain by organic-rich shales that provide the source for conventional hydrocarbon. The primary objectives for exploring the gas-rich shale plays and unconventional reservoirs in the Western Desert were to evaluate the Middle Jurassic Khatatba source rock reservoir qualities, demonstrate the availability of reserves, and identify optimal technology to maximize productivity of unconventional low-permeability reservoirs, stimulation, and testing strategies. In 2014, a vertical exploratory data well was drilled and completed in the appraisal program before the completion of horizontals in this formation. Logs, core testing, and analysis service data were performed on or collected from this well. A stimulation model was built, which integrated petrophysical and geomechanical data. This model was used to aid the completion and stimulation design, including fracturing fluids and proppant selections. One-stage hydraulic fracturing was implemented, and the well was then flowed back and produced. The Khatatba Shale was systematically studied in this work. Various methods were used to understand this source rock. A geological study identified the lithostratigraphic section of the Khatatba Shale formations by collecting core samples. Core tests measured total organic carbon (TOC), brittleness, and sensitivity to fluid. These understandings helped reduce uncertainty during hydraulic fracturing operations. A successful hydraulic fracturing treatment was performed for this formation, which showed that low-viscosity fracture fluid can be used as the treatment fluid to carry proppant into the formation. During fracturing, near-wellbore (NWB) multiple fractures can be an issue. From an operational point of view, there might be options better than performing high-rate fracturing treatments. The lessons learned from this work and presented in this paper helped define completion and stimulation technologies for horizontal wells. This paper presents hydraulic fracturing treatment of the first shale gas well in Egypt for the Khatatba formation. Lessons learned about geochemical, rock mechanical, and petrophysical properties of this shale formation and their effects on hydraulic fracturing and production formed the basis for subsequent development of various shale plays in Egypt and worldwide.

The Glauconite Formation is a low permeability unconventional resource in southern Chile. Like many unconventional reservoirs outside the United States establishing commercial production from the Glauconite Formation was difficult given the nature of the reservoir, the availability of equipment and materials, and the logistics associated with drilling, completing, and fracture stimulating wells in a remote area like Tierra del Fuego in southern Chile. To be successful fracture stimulating wells in this environment it was critical to develop a deep understanding of the relationship between reservoir quality, completions, mini-frac analysis, fracture design, execution, and post fracture production data. To this end, a database was developed and the key completion and fracture stimulation parameters were captured. This paper describes a statistical evaluation of nearly seventy wells fracture stimulated in the Glauconite Formation in southern Chile. The analysis will attempt to discover the key fracture design parameters that drive well performance in this unconventional resource. Some key questions to be addressed include: What type of fracture fluid (cross-linked, linear gel, hybrid, or treated water frac's) results in better well performance? What is the effect of treatment volume on well performance? What is the effect of proppant volume, proppant type, and proppant size on well performance? Is there a relationship between fracture fluid efficiency, load recovery, reservoir quality and well performance? These and more questions will be addressed in this paper. This paper will also use the information in the database and the results of the statistical evaluation to conduct a fracture optimization study and determine the optimum fracture design which maximizes well performance and economic objectives. This work benefits the petroleum industry by: Conducting a statistical analysis of the important completion and fracture stimulation parameters to determine the success drivers for well performance in an unconventional tight gas reservoir, Utilizing the statistics to identify well completion and fracture stimulation risks and risk mitigation strategies,

As an alternative to conventional proppant pack placement, propped pillar-fracturing promises more effective and conductive fractures by enabling hydrocarbons to flow through open channels. Recent experimental and numerical studies confirmed that viscous fingering phenomena can be used to develop a proppant pillar-fracture type placement: High-viscosity, proppant-laden fluid is placed, and then a low-viscosity clean fluid is pumped to carve pathways through the proppant-laden fluid in a dynamic, continuous process. However, the created channel pattern was found to be significantly dependent on fracture geometry and treatment design parameters such as injection rate, fluid pulsing time, and fluid viscosity ratio. The objective of this study is to extend the numerical investigation and normalize it to develop a treatment design methodology for constructing proppant pillars throughout the created fracture. A computational fluid dynamics (CFD) model was constructed using commercial CFD software, simulating the flow of fluids inside the fracture and the resulting proppant pillar generation. The study focused on the effects of surface injection rate, pulsing time, and viscosity ratio between the two injected fluids, to develop correlations between all these parameters and the created fracture geometry. Based on numerical results, the viscosity ratio chosen to achieve the proppant pillars allows for the use of conventional crosslinked fluid without the need for a hindered settling agent. The optimum channel pattern has small channel sizes, remains open under closure stress, creates more channels distributed throughout the entire fracture area, and maintains good communication between unpropped areas. A new dimensionless term, Dimensionless Stage Volume (V SD ), is presented to describe the channel pattern inside the fracture. The settling of proppant occurs after the pumping of the job has ended, and prior to fracture closure, yielding wider pillar widths compared to current pillar-fracturing treatment techniques. A combination of conventional proppant and ultra-lightweight proppant can be continuously pumped as part of the treatment schedule. The application of lightweight buoyant proppant positioned within the created channels supports and braces against possible fracture closure between proppant pillars.

In the end of 2012, the breakthrough of 15 stages fracturing treatment of horizontal well-JiaoYe 1HF, located in Jiaoshiba block, Fuling gas play, Chongqing, China, with the post-fracturing gas production 203,000 m 3 /d ( Lu, et al., 2013 ; Zhou, et al., 2013 ), which opened the new page of shale gas exploration and development in China. The reason of the success may be owed to the adaptable strategy and corresponding parameters so as to maximize Effective Stimulated Reservoir Volume(ESRV) ( Jiang, et al., 2011 ; Jia, et al.,2012 ). A systematic method was employed in this study which contains physical simulation in lab, numerical simulation, and fracturing fluid additives development as well. Firstly, a comprehensive formation evaluation was conducted such as rock lithology, pore throat size, porosity, permeability, rock mechanics, three dimensional stress, pore structure, maturity, total organic content, total gas content including free gas and absorbed gas, etc ( Jia, et al.,2012 ). Secondly, a three axis laboratory test of fracture propagation physical simulation on a lot of large scale rock samples were conducted, from which the network fracture mechanism and correspondingly, the key control factors may be available consequently( Zhang, et al.,2013 ); Thirdly, a systematic laboratory tests of fracture conductivity for many conditions such as various fracture type and, proppant type, concentration and placement mode in different closure stress and time, etc. were conducted, so that the conductivity characteristic of network fracture may be obtained so as to utilize in the design of pumping schedule( Jia, et al.,2014 ); Fourthly, a new mathematical model of coupling flowing interference and stress shadow interference was put forward and a "W" type fracture distribution was correspondingly anticipated. After that, a new optimization model for well pattern and well space, fracture parameters and fracturing treatment parameters can be optimized simultaneously ( Jiang, et al., 2013 ). Fifthly, alternately pumping mode of "spearhead acid, slick water, gel, slick water, gel……" and "70/140 mesh proppant, 40/70 mesh proppant, 30/50 mesh proppant "was put forward based on the object of main fracture net pressure during the course of fracturing treatment( Jiang and Jia, et al, 2011 , 2013 ). Sixthly, a new flow back model was put forward and the relative flow back parameters such as shut-in time and flow back rate as well may be optimized correspondingly( Jiang, et al, 2013 ). The above mentioned technology have been applied in a large scale (more than 200 wells) in Fuling shale gas play, therefore, expected results are obtained with the average gas production more than 300,000 m 3 /d, and the highest open flow capacity as high as 1,580,000 m 3 /d. Now, Fuling shale gas field is the largest one in China, its annual production is more than 5 billion m 3 . Therefore, it has a great significance on the hydraulically fracturing technology in other lithology such as tight sandstone and carbonate reservoirs.