We introduced fracture hydrodynamics and in-situ kinetics model capable of simulating particle size distribution of propping agent. We demonstrated on several cases that accounting for particle size distribution in numerical simulation of hydraulic fracturing results in a noticeable difference of predicted fracture geometry and conductivity, as compared to the modeling approach where propping agent is represented by one effective mean diameter.

To unlock unconventional reservoirs for optimum production, maximum contact with the reservoir is required; however, excessively dense well placement and hydraulic fractures interconnection is a source of well-to-well interaction which impairs production significantly. The first step to have successful and effective well completion is to understand the characteristics of the hydraulic fractures and how they propagate in reservoir. This paper demonstrates an integrated approach with a field example in the Montney formation for how modern modeling techniques were used to understand and optimize hydraulic fracture parameters in unconventional reservoir. Advanced logs from vertical wells and 3D-seismic were used to build an integrated geological model. Lamination index analysis was performed, using borehole imagery data to account for interaction of hydraulic fracture with vertically segregated rock fabric and to provide additional control on hydraulic fracture height growth during modeling process. A non-uniform Discrete-Fracture-Network (DFN) model was constructed. 3D-geo-mechanical model was built and initialized, using sonic log and seismic data. Fluid friction and leak-off was calibrated, using treatment pressure and DFIT data. Hydraulic fracture modeling was done for pad consists of 6 horizontal wells with multi-stage fracturing treatments, by utilizing actual pumped schedules and calibrating it against microseismic data. High-stress anisotropy led to planar hydraulic fractures despite presence of natural fractures in area. Fracturing sequence, i.e., effect of stress shadow, is seen to have major impact on hydraulic fracture geometry and propped surface area. Heatmaps were generated to estimate average stimulated and propped rock volume in section. It was also observed that rock fabrics, i.e., natural fracture and lamination has considerable impact on propagation of hydraulic fracture. Multiple realizations of natural fracture and lamination distribution were generated and used as an input in modeling process. High resolution unstructured simulation grids were generated to capture fracture dimensions and conductivities, as well as track propped and unpropped regions in stimulation network. Dynamic model was constructed and calibrated against historical production data. History matched model was then used as predictive tool for pad development optimization and to evaluate parent-child interaction in depleted environment.

Optimal proppant placement is critical to maintaining productivity from stress-sensitive reservoirs, in which gas conductivity depends on the connectivity of the network of secondary fractures to the wellbore. In a colloquial sense, this research places micro-proppants in induced and natural fractures, shows how they are excluded from reaching far into the reservoir, and describes which sizes of proppants this occurs for. Micromechanical modelling of a hydraulic fracturing fluid, in which the hydrodynamics between the fluid and solid phases are fully resolved, is achieved via the lattice Boltzmann method (LBM) for fluids coupled with the discrete element method (DEM) for particles. It is shown that proppant transport along the primary hydraulic fracture channel is strongly inhibited by leak-off into the secondary fracture system. This leak-off is strongly affected by the migration of particles across the fracture width, which in turn is a function of reservoir and treatment properties. A novel numerical approach is proposed for predicting proppant transport through the secondary fracture system, with far-reaching applications to porous media particulate transport.

Hydraulic proppant fracturing is one of the most effective tools to optimize production in the mature, low- permeability reservoirs found in the Pannonian Basin in Central Europe. Fracturing can effectively enhance production by improving reservoir contact, but for wells already producing with high water cut, even a small fracture extension into a water-bearing or "wet" zone offsets the gains in hydrocarbon production. Fracture geometry control (FGC) techniques limit increases in water cut, which is one of the greatest challenges to extending economic production and maximizing ultimate recovery for mature wells. Artificial barrier placement and proppant channel fracturing were proven to improve hydrocarbon production while fracturing stimulation targets adjacent to high water saturation intervals. The pilot included candidates in thin, low-permeability sandstone reservoirs, located within 5 to 10 m of wet intervals. An integrated engineering approach to fracture height growth was applied, including a new proppant transport model to predict fracture geometry improvement using the FGC solution. The FGC solution consisted of injection of an engineered particulate mixture designed to bridge at the fracture edges and arrest height growth. Additionally, the bridging mixture provided reduced conductivity and acted as a fracture flow restriction for water. The FGC solution was also combined with channel fracturing in some trials as an attempt to reduce net pressure development, minimize the risk of height growth and improve fracture quality in the low-permeability reservoirs. The new engineering approach, incorporating the new solids transport simulator, enabled the successful implementation of the FGC technique in the pilot candidates. Fracture height control was achieved in absence of good geological barriers. The benefits of this new approach are supported by a consistent improvement in hydrocarbon production without an increase in water cut. In field A, the combination of FGC and channel fracturing resulted in additional production when compared to wells where only FGC was implemented. Evaluation of this pilot included a comparison with offset wells stimulated without this technique when a water cut increase was always observed in the field A. This paper describes the first implementation of the complex technology and engineering solution to control fracture height for conventional wells in the Pannonian Basin. For the first time, the mixture of solids was modeled directly, and the influence on fracture geometry and production results is shown. The cases are of significant interest because of the global challenge of maximizing recovery from mature reservoirs with nearby water hazards. The application of a full engineering process for the design, placement, and evaluation of the fracture height control treatments provides an improved degree of confidence that such operations can result successful production optimization. The workflow as presented and applied is an effective tool to reduce risk of high water production when fracturing close to water contacts.

The success in shale oil and gas over the last decade is based on massive multi-stage hydraulic fracturing. Applying the same well concept on conventional tight and low permeable reservoirs can bring economically stranded projects into consideration again. However, simulating production over time for multi-stage hydraulic fractured wells using conventional full-field reservoir simulation models can be challenging. Detailed modelling of the hydraulic fractures comes with a large computational cost and typically a number of convergence issues. Simplified methods fail to capture the full pressure loss from the reservoir into the well. In this work, a method with effective Virtual Perforations is described, enabling both efficient simulation and prediction of well performance. A detailed 2D mesh for each hydraulic fracture is used together with the unmodified reservoir model grid, integrating geomechanical fracture propagation simulation results directly into the reservoir simulation workflow. The Virtual Perforations are defined by the geometrical intersections between the fractures 2D meshes and the reservoir model 3D grid. The numerical solution of the fracture-to-well inflow system provides a set of effective Virtual Perforations transmissibilities for Darcy flow which can be applied in any standard reservoir simulator. In the reservoir simulation model numerical multipliers, in-active grid blocks or gaps in grid model layers can act as barriers for vertical flow in the fractures. Hence horizontal, fractured wells may not capture the full flow potential in reservoir simulations. In this work, the effective Virtual Perforations are calculated based on the vertical fracture mesh to ensure well flow from the full height of the hydraulic fractures. Using a 2D mesh for the fracture, the fracture geometry can be contained within certain grid model layers or truncated by faults. Matrix condensation methods known from degree-of-freedom reduction in structural analysis, are applied to efficiently calculate all the effective Virtual Perforations transmissibilities. Thus, working with well completion design can be done interactively. For gas reservoirs, a non-Darcy pressure loss model is established based on the Forchheimer model. Fracture width and proppant inertial flow parameter for a given confinement stress are used to calculate the rate-dependent skin factor for each fracture. The rate-dependent skin factors are provided for the all the Virtual Perforations in such a way that they all get the same additional near wellbore non-Darcy pressure loss. This work has been implemented in the open-source visualization application ResInsight. The application has been used successfully for well planning in field development projects, including as part of automated workflows for ensembles of reservoir models.

We demonstrate the advantages of a new hydraulic fracturing simulator comprising a fine-scale fracture hydrodynamics and in-situ kinetics model. In contrast to existing commercial modeling tools, it has a sufficient resolution and other functionality for adequate representation of modern stimulation technologies: pulsing injection of proppant, mixtures of multiple fracturing materials (fluids, proppants, fibers, etc.), materials degradation, etc. This simulator accounts for the influence of materials distribution on fracture propagation and calculates fracture conductivity distribution. We coupled it with a production simulation model and established a complete framework for hydraulic fracturing treatment design. In addition to the selection of the pumping schedule, this model can be used to define specifications for novel hydraulic fracturing materials. This is a step change tool for wellbore stimulation and production forecast.

Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. Ineffective completion practices, fracture design, and reservoir heterogeneity have generally been blamed for the variability in the performance. Limited importance has been attached to drilling quality and well trajectory placement in the current approaches by the operators. The objective of this study is to demonstrate an engineered lateral landing approach for improved long-term productivity in the unconventional reservoirs. Coupling the reservoir model to the wellbore and accounting for the transient flow behavior are important for improving deliverability in horizontal wells. The study in this paper encompasses a field case study of a geocellular and geomechanical earth model in the Permian basin, which involves hydraulic fracturing modeling, reservoir simulation, fluid flowback, and transient wellbore flow modeling. Pressure losses accounted for in the reservoir, in the near-wellbore region, and in the wellbore profile are modeled and calibrated with bottomhole and surface gauge measurements. Complex hydraulic fracture geometry and numerical reservoir simulation are used to characterize the pressure losses in the reservoir. Transient wellbore fluid flow considerations are used to evaluate the pressure losses in the wellbore. Based on the fracturing fluid type, the conductivity profile of the hydraulic fractures, connection to the wellbore, and coverage of the pay zone are important criteria in considering the landing location for wells in unconventional reservoirs. However, having the most effective hydraulic fracture design is not enough to decide the well trajectory. Mitigating liquid loading, fluid flowback, proppant settling, and cross-flow of reservoir fluid helps to diagnose the true production potential. Therefore, transient flow models were coupled to the reservoir and fracture models to design a more-effective well trajectory. The study demonstrates the need to couple the wellbore model to the reservoir simulation and hydraulic fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity. The methodology provides the first integrated data workflow for well drilling and trajectory planning in unconventional reservoirs that is generated from the perspective of reservoir potential and deliverability. Although variances exist in completion effectiveness due to reservoir heterogeneity, applying the robust modeling workflow as discussed in this study would help deliver consistent results that can be used in field management and EUR estimates across various shale basins.

An operator working in Oklahoma's STACK play continues to analyze its completion program in an effort to identify the optimal balance between cost-effectiveness and production. A recent study of field results from four pads with two different completion methods on each pad, shows a difference in fracture performance between the two methods, as well as resulting production. Each of the four well pads was developed with one ball-activated uncemented multistage completions and a cemented liner completion using either sliding sleeves or plug-and-perf. The methods on each pad targeted the same horizon in the STACK play, which is made up of multiple formations. The wells on each pad were stimulated with the same treatment program, and the performance of the wells was analyzed using microseismic, sidewall cores and extensive logs. Additionally some of the pads were also tested with diverter. Daily OWG rates were also reviewed, and a cost comparison between the two completions on each pad was conducted. The STACK play is predominantly completed using plug-and-perf methods. These wells have long laterals and are typically stimulated with large amounts of fluid and proppant. All the wells in this study were completed with common stimulation programs for the area. Despite the typical estimated frac length, three of the subject wells experienced offset stimulation interference from offsetting wells or pads. These "frac hits" contributed negatively on the producing wells for a period of time. On all the pads, the wells completed using uncemented multistage completion systems had lower CAPEX Quicker completions and easier millouts helped contribute to the lower upfront CAPEX. The uncemented multistage wells also flowed back initially at higher rates. This paper compares a new completion method attempted in one of the most active plays in the United States. As well as the diagnostic, completion and cost comparisons, the impacts of a "frac hit" on producing wells and suggestions to reduce negative outcomes from the hits will be discussed.

Romania is a key pioneer in oil and gas industry with a history of more than 150 years'experience. Many of the oil fields discovered in the early days are still being produced. Extending the production life of mature fields presents a variety of challenges including low reservoir pressure, high water cut, limited well data, aging completions and bypassed pay. The target field is a mature oil field situated in the heart of Romania that has been operated since the 1960s and exhibits many of the aforementioned issues. This paper describes the reservoir, exploitation difficulties and new techniques applied to overcome the key challenges to effectively producing this aging asset. Production enhancement in mature assets require new approaches that can address key challenges and risks associated with the reservoir and completion age. Application of conventional can easily lead to failures including ineffective stimulation, completion failure, screen-out, and increased water cut, all causing difficulties to put wells back in production and resulting in disappointing results. In mature fields, a different approach is required. This paper details first time application of the flow channel hydraulic stimulation in one of the wells in the field, describing the importance of well candidate selection phase, engineered design, execution, and evaluation. The applied channel hydraulic stimulation combines geomechanical modeling with intermittent proppant pumping and degradable fibers to obtain heterogeneous placement of proppant within the fracture. A post job production evaluation compares the production after the conventional treatments versus post flow channel hydraulic stimulation job. The results for all conventional hydraulic stimulation treatments show a steep production decline rate, while the positive impact of channel hydraulic stimulation is apparent resulting in higher initial production and an overall slower production decline. The productive reservoirs besides of low reservoir pressure, are characterized by an increased degree of lamination. The target interval is usually described by a sequence of marls and lenticular streaks of sandstone and shaly-marly sandstone. Conventional hydraulic stimulation treatments have had a marginal effect in this reservoir. Due to the variable lithology, gained limited connection through conventional ways of stimulation and/or perforation end up in quick depletion and production decrease. Channel hydraulic stimulation was applied for the first time in this field and may now be considered to be an efficient way of enhancing production in this and similar reservoirs.

Egypt's Western Desert reservoirs are characterized to be tight clastic reservoir. In the early development stages only layers with high permeability were produced while tight formation was not considered economic due to application of conventional completion strategy resulting in very low production results. With the decline of Egypt's hydrocarbon production and increase in domestic demand of energy, economically production from these tight reservoirs is a great challenge to maintain production's annual decline. The prospective of these tight producing zones were discovered at a depth below 14,000 feet where the stress is extremely high (1.1 psi/ft) and the reservoir permeability conditions are low with range of 0.2 mD; being necessary in all cases to fracture stimulate each horizon to define the fluid and evaluate productivity. The extreme stress condition and high fracturing treating pressure, risk of premature screen out are one of the main challenges to perform fracture stimulations on these formations which exceeded the working capability of the available equipment in addition; it required significant amount of horsepower on location. Initially, the conventional fracturing treatment was conservatively designed in terms of treatment rate, polymer loading of fracturing fluid and proppant concentration to manage both risk and treatment proppant placement. However, this conservative approach impaired proppant-pack conductivity and the effectiveness of the fracture half-length However, premature screen-outs severely disrupted stimulation operations, leading to costly nonproductive time and deferred production. The poor results using these conventional fracturing techniques during initial exploration and development, the wells were deemed uneconomical. The recent advances in channel fracturing technology; enabled operators to unlock the potential of their toughest reservoirs to economically produce and unlock the enormous amount of hydrocarbons retained in the rock, prolong life of mature fields and achieve production targets. With the application of this technique, helps alleviate the risks of screenout and mitigates the proppant bridging buildup, as the proppant is added in pulses along with dissolvable fibers. These proppant pillars are suspended and held in place by fibers during the treatment. Once pumping is stopped, the fracture closes on the proppant pillars and the fibers degrades under effect of formation temperature. These pillars hold stable channels along the entire geometry of the fracture that provide open pathway for hydrocarbons to flow in near-infinite conductivity. Additionally, 40% less proppant was used and reducing pump rates, which lowered horsepower requirements by 30%. Results indicate that the channel fracturing technique has significantly impacted wells' performance and achieved the desired objectives over conventional fracturing methodologies. Positive features that were observed such as reduced net pressure increase estimates, elimination of near-wellbore screen-outs.

Uniform proppant distribution in multiple perforation clusters plays a crucial role on sufficiently propping fractures conductivity in hydraulic fracturing. These propped fractures and their effectiveness is critically influenced by the in situ stress in the formation. As great uncertainty exists in uneven propped fracture, this paper examines the impact of proppant distribution and fracture conductivity variation on the gas productivity for shale gas reservoirs, by developing a reservoir simulation model. In this paper, numerical reservoir simulation, which involves application of a constantly decreasing permeability to the propped fracture, are used to model the uneven proppant distribution and geomechanics effect. The decrease of permeability, along from the wellbore toward the tip, is simulated using an exponential approach, as well as a linear approach. Moreover, Effects of gas desorption and stress-dependent fracture conductivity are taken into account in this model. Sensitivity analysis is carried out on critical parameters to quantify the key parameters affecting gas productivity between uniform and nonuniform proppant distribution. The degree of non-uniform proppant distribution is also investigated and divided into four types of proppant distribution scenarios. The following conclusions can be obtained based on the simulation results. A big difference on well performance between the case of linear and exponential permeability degradation is observed. The pressure distribution comparison shows higher pressure drops in the exponentially decreasing permeability case, which results in a lower gas production. Reservoir permeability plays a critical role in cumulative gas production, no matter in case of permeability exponentially degrading or linear degrading, followed by fracture half-length, primary fracture conductivity, Fracture complexity, permeability anisotropy. Furthermore, the effect of uneven proppant distribution between different clusters can significantly reduce the gas recovery, especially in low proppant concentration and small fracture conductivity. The model presented in this paper takes the uneven proppant distribution and geomechanics effect into consideration and shows good agreement with real field production. This paper can demonstrate its own merits on the optimization of hydraulic fracturing treatments, and provide a better understanding of the effect of proppant distribution on well performance.

Cross-linked hydraulic fracturing fluid gel can induce high damage in the fracture when left for a long time. Any residual gel not produced back reduces the conductivity of the fracture and the well productivity, leading to an extended flowback for a cleanup operation, which is not cost-effective. The objective of this study is to assess the cleanup operation effectiveness by conducting a laboratory testing on the flowback fluid samples from hydraulically fractured three development wells to optimize flowback duration and cost, and minimizing formation damage; and thereby enhancing well productivity. These wells are drilled in a clastic Devonian gas reservoir in Saudi Arabia. This reservoir has a range of permeability varying from tight (0.1 mD) that requires stimulation to highly prolific (greater than one Darcy) that produces naturally. The laboratory analysis technique that was used for assessing the cleanup effectiveness is based on determination of the polymer content in the flowback of the fracturing fluid with a size exclusion chromatography (SEC). The technique provides the polymer concentration in the return fluid in a series of samples collected throughout the cleanup operation. The polymer strength of the residual fracturing fluids can then be inferred from the polymer concnetration and the production performance. This study shows that the SEC technique is effective to qualitatively determine the residual polymer content. The results are useful in establishing trends for the effective flowback practices based on different reservoir and fracture characteristics. Using the laboratory results to optimize these parameters, formation damage can be minimized and well productivity will be ultimately enhanced.

The application of enzymatic generation and precipitation of calcium carbonate for the use as in-situ proppant consolidation is an environmentally green technology that shows promise in the Danish North Sea. Hydraulic fracturing of producers with the aid of proppants to keep fractures open can present a problem if the proppants are back-produced as this can cause erosion of the well and production facilities. These problems may result in delayed production and costly workovers. Enzymatic calcium carbonate, a technology to consolidate the proppants, can be applied right after a hydraulic fracturing treatment or at a later stage, when proppant reconsolidation is needed. In this paper, we report the findings of extensive lab experiments, under reservoir conditions, on consolidation of of three different proppant types. The results show that some proppants are easier to consolidate than others.

Channel fracturing, which greatly increase fracture conductivity by the creation of open channels inside fracture, has proved to be a novel stimulation technology that widely used in unconventional reservoir. The objective of this paper is to study the stimulation mechanism of channel fracturing by the combination of theoretical analysis and experimental research. However, for channel fracturing scenario, the currently available models are not accurate and appropriate in terms of prediction of proppant embedment and fracture conductivity in channel fracturing. In this paper, new analytical models are derived to compute the proppant embedment, proppant deformation and fracture conductivity in channel fracturing. The mass deformation model and creeping deformation model are adopted to predict the change of proppant embedment and fracture conductivity over time. Many factors affecting the results of proppant embedment and conductivity, including closure pressure, elastic-plastic properties, properties of viscoelastic proppant and rock are investigated. Experimental researches are also conducted to evaluate conductivity at different closure pressures for the fractures of steel plate, shale and sandstone. Besides, the proppant embedment and proppant deformation are measured through the proppant embedment testing instrument, and the proppant distribution before and after experiments are comparatively analyzed. The results show that the new analytical model proposed fits well with the experimental data, which verifies the accuracy and the feasibility of this model, though the decline rate of experimental data is a little bit faster than that of the model. The fracture conductivity is directly proportional to proppant viscosity, elastic modulus of proppant and inversely proportional to closure pressure, while elastic modulus of rock and large value of formation rock viscosity have slight impact on fracture conductivity. Moreover, the steady state of conductivity has been studied, and Comparisons between channel fracturing and conventional fracturing are analyzed in several aspects. The experimental results also reveal that the overall dimensions of created open channel may decrease or disappear due to the forced of formation stress. Technical innovations in this paper are (a) new analytical models, including the mass deformation model and creeping deformation model, are adopted to predict the change of proppant embedment and fracture conductivity (b) Experimental tests are also performed to measure conductivity and proppant embedment at different closure pressures. This paper can demonstrate its own merits to show the advantage of channel fracturing technology.

Economic recovery and production of non-associated gas from the tight clastic reservoirs in Saudi Arabia faces some challenges resulting from high bottomhole temperature, high in-situ stress, low permeability, and high Young's modulus and rock compressive strength. Hydraulic fracturing, a necessary means to exploit the tight reservoirs, encounters constrains such as high fracture initiation and treating pressure, risk of pre-mature screen-out, and conductivity degradation with time. A conventional fracturing treatment in such challenging environment necessitates increased polymer loading in fracturing fluids to stabilize fluid viscosity and using smaller size proppant at low concentrations to ensure proppant placement. This results in shorter effective fracture half-length and low fracture conductivity. Reduced contact area decreases production potential. Additionally, high polymer loading is not easily breakable and may create major damage to the proppant pack, thereby substantially reducing fracture conductivity. The challenges compound when the reservoir is relatively tight and often cannot generate enough energy to clean up the injected fracturing fluids. To overcome these challenges, channel fracturing was introduced where proppants are added in pulses in fracturing fluids along with dissolvable fibers creating stacks of pillar-like structure inside the fracture. These proppant pillars stay suspended and are held by the fibers during the treatment. Once the pumping is stopped, the fracture closes on the pillars and the fibers degrade under formation temperature. These pillars hold the fracture open and act as columns; the void surrounding them are essentially stable channels along the entire geometry of the fracture that provide open pathway for hydrocarbons to flow in a near-infinite conductivity environment. The technology also reduces the amount of proppant pumped compared to a conventional treatment, and pulsation of proppant during pumping reduces the risk of an early screen-out.

The Grove field is located in the Southern North Sea and has been in production since 2007. The Grove A well lies within block 49/10a and was originally planned by Centrica as an infill well, drilled horizontally in the central fault compartment of the Grove field structure. The well targeted the relatively undepleted basal "A" sandstone unit of the Late Carboniferous, Westphalian reservoir, also known as the Barren Red Measures (BRM). The well objectives were to 1) target the Grove A sand from the G1 "donor" well, 2) establish a suitable completion strategy for field development, 3) assess the performance of a multiple stage (four to five) hydraulically fractured horizontal well, 4) acquire sufficient log data to fully evaluate the reservoir, and 5) acquire reliable permeability and reservoir pressure measurements to assist in reservoir simulation. The A sand reservoir unit has a porosity of approximately 10% and permeability between 0.05 to 1 md, with a reservoir with true vertical thickness (TVT) of approximately 140 ft at the heel and 40 ft at the toe. The reservoir unit is poorly drained by the other wells, and the Grove infill well is the first horizontal gas well in the field to be stimulated by means of multistage hydraulic proppant fracturing. The hydraulic fracturing treatment used sand plug isolation to separate consecutive fracture stages, and the fracture stimulation operations were performed with the rig in place by means of a converted stimulation vessel. The stimulation treatments successfully used a modified sand plug methodology that employed aggressive breaker schedules and fluid injections rates that were determined to be more efficient than previous treatments based on employing strict "sand plug setting" criteria. The findings are presented, as well as analyses of both prefracturing and fracturing data for the treatments together with results of the well post-completion and hook-up production. This work should be of interest to offshore operators world-wide performing multiple hydraulic fractures in both horizontal and vertical wells using sand plug isolation technology.

Analysis of flowback and produced waters for surfactant residues showed that a majority of surfactants were retained inside the reservoirs ( Rane and Xu 2015 ). While it is beneficial that surfactant typically does not flow back and continues to contribute to production increase, it is uncertain where in the reservoir the surfactant is actually retained or distributed. A plausible mechanism is that most surfactant may plate out prematurely on the formation rock in the near-wellbore (NWB) region, potentially restricting surfactant travel deeper into the reservoir. This paper discusses the study of a solution using a sacrificial agent (SA) to adsorb onto the formation surface which enables surfactants to further penetrate the Eagle Ford (EF) formation during a hydraulic fracturing treatment. Laboratory testing revealed that injection of 1 gal/1,000 gal surfactant in the presence of 1 gal/1,000 gal SA enabled minimum adsorption of the surfactant on both proppant and formation rocks. Notably, the addition of SAs resulted in lower interfacial tension between fluids and enhanced hydrocarbon solubility. As a result, oil recovery was enhanced considerably. Additionally, approximately 70% friction reduction of the fracturing fluid with surfactant and SA was achieved and fluid stability and compatibility with standard guar-based fracturing fluids was also verified, thus providing compelling evidence for field trials.

Hydraulic fracturing has been a common practice in US. The chemistry of hydraulic fracturing fluids is very complicated, which makes the optimization process challenging. In designing fracturing fluids, one of the major unknowns is the fluid chemistry. Therefore, understanding the chemistry and interactions between chemicals to form a strong gel is a must. A strong gel is a factor of different parameters such as polymer loadings, crosslinker concentrations, buffer systems, and temperatures. Different crosslinkers such as boron and several metals including titanium, zirconium, and aluminum have been used in the oil and gas industry. Aluminum and boron reside in the same group on the periodic table. The latter means that there are some similarities in their chemistry. Aluminum chemistry is critical in the preparation of highly effective aluminum-based crosslinkers. Therefore, the objective is to 1) investigate the performance of two new Al-based and Al-Zr-based crosslinkers to form a stable gel with Carboxymethyl hydroxypropyl guar (CMHPG) at high temperatures and shear rates, and 2) determine the leakoff rates of the cross-linked gels with the optimized formulations. New aluminum-based and aluminum-zirconium crosslinkers to form a stable gel with guar derivatives are studied. This study investigates various parameters including polymer loading, crosslinker concentrations, pH, and temperatures to form a high quality gel. High viscosity gels increases fracture width, and also can carry higher concentrations of proppant that leads to fluid loss decrease and enhances the propant transport. The results of this study indicate that Al-based crosslinkers at pH 10.8 and 3.8 are very effective in forming high quality gels that are stable at temperatures up to 250°F after 140 minutes. Varying shear rate is studied and the results showed that the Al-based crosslinkers in this study are stable at shear rate of 170 s −1 if an optimized formulations is chosen. It is found that forming a stable gel is strongly a function of concentrations of Al crosslinkers as shear rate increases. Time and temperatures delay in forming gels can be achieved through the optimization of pH, crosslinker concentrations, and polymer loadings. Extensive lab research and understanding the chemistry of crosslinkers help to design a successful field treatment.

The intrusion of formation fines and formation sand grains into the proppant pack drastically reduces the conductivity of propped fractures, which can negatively impact well production. This paper describes the development and field treatments using a new form of surface modification agent (SMA) that is a low-tackiness surface modification agent (LTSMA) that can be applied during primary hydraulic fracturing or remedial treatments of propped fractures. Studies were conducted to demonstrate the mechanisms by which this LTSMA controls migration and intrusion of formation sand and fines into the proppant pack, while inhibiting scale formation in the treated pack. Molecular modeling data on the LTSMA suggests that both the polymer backbones and the hydrophobic chains on the polymers are responsible for its reduced tackiness to the treatment equipment and significant scale inhibition ability. Once coated on the proppant as part of hydraulic fracturing treatment, or injected into the proppant pack and formation matrix surrounding the fractures, this LTSMA forms a thin film on the particulates, covering and anchoring the particulates in place. This LTSMA coating also forms a hydrophobic film on the particulate surfaces, inhibiting chemical reactions that lead to scale formation in the pack matrix and subsequent productivity losses. Laboratory experiments using packed beds of proppant, formation sand grains, and various fines were performed to simulate proppant pack conditions and formation fines before and after remedial treatments. Experimental results indicate that treatments with this particular LTSMA effectively control the migration of formation fines into proppant packs and successfully prevent the buildup of scale in various sand packs to maintain the fluid flow paths. No pressure buildup was noticed, opposed to the proppant that was not treated with the LTSMA, for which severe scaling had occurred by 24 hours, leading to an exponential increase in pressure drop across the proppant pack. Examination with scanning electron microscopy analysis clearly demonstrated that no scale was formed in the pore spaces between the treated proppant grains compared to a massive buildup of scale on the proppant particles and in their pore spaces when not coated with the LTSMA. In addition to remedial treatments, LTSMA treatment fluid can be applied while treating formations following an acidizing treatment, during treatment of formations before a high-rate water pack or frac-pack treatment, or as part of a pad fluid to treat the fracture faces before placement of proppant into a fracture and/or a screen annulus.

Well Ba-E-1 was drilled in the Tompa prospect (now the Ba-IX Mining Plot) in Hungary targeting the Miocene and Cretaceous formations between 2600 and 3500 mTVD. These are tight sandstones and the expected permeabilities were in the range of 0.001 to 0.5 mD. Two hydraulic fracture treatments were performed. The first fracture treatment was in the lower part and the second treatment was in the upper part of the deepest interval. With no previous propped fracturing experience in this field, the first treatment was designed as a conventional crosslinked gel treatment to minimize the risk of a premature screenout. Following the analysis of the data from the first zone, it became clear that the average permeability was closer to the minimum expectation of 0.001 mD. Due to lower than expected stimulation effectiveness of the first fracture, and the confirmation of the low permeability, the 2 nd fracture treatment was changed to a waterfrac design. This formation clearly falls into the category ‘unconventional’, and consequently was a good candidate for a waterfrac. This paper describes the pre-frac diagnostics, fracture execution and post-frac production evaluation of this unconventional gas well. Special emphasis is placed on the use of small volume injection tests (DFIT) to obtain an estimate of the in-situ kh , since it is impossible to perform pre-fracture welltests in such a formation. The result of the DFIT analysis is then used to constrain the post-fracture welltest analysis in a numerical simulation model that includes fracture filtrate cleanup modeling. Post-frac analysis showed that the initial proppant pack damage is high and effective fracture length is much smaller than the created length, especially with crosslinked gel. The crosslinked gel treatment was not able to cleanup effectively, and therefore showed limited stimulation effectiveness. The first ever waterfrac in a gas reservoir performed in Europe showed a more significant production improvement during the short post-frac test. The results from this well suggest that, as in North America, waterfracs appear to have better initial production than crosslinked gel fracs due to better fracture cleanup in European reservoirs with micro Darcy permeability.