Substantial amounts of gas are accumulated in tight sand reservoirs in Cooper basin, Australia. This basin has a complex geomechanical stress regime. It is believed that the orientation of the minimum horizontal stress is changing and also there is a stress dependent permeability in this basin. These characteristics have a major impact on the gas recovery from different fields in Cooper basin. It is well known that permeability decreases in sandstone reservoirs when the net confining stress on the rock increases as the gas pressure in the reservoir decreases, so permeability is reduced by gas production. This permeability reduction is more pronounced in tight sand reservoirs due to shear dilation of micro-fractures. In order to model stress dependent permeability, a fully coupled finite element geomechanical reservoir simulations is needed. However, since a large number of data and high computational time is required for this kind of modeling, stress dependent permeability model is a short cut for reservoir simulation. This paper presents an alternative approach of partial coupling of geomechanics and reservoir simulation in which only a finite difference simulator is used with much less computational time and lower cost. In order to prove stress dependent permeability and develop a model, first a three dimensional hydraulic fracture model is constructed based on wire-line logs and mini-frac tests, then the resulting fracture geometry and conductivity are used as input data for dynamic reservoir flow simulation. We found that the reservoir permeability is changing at different time periods during pressure and production history matching. In this paper a stress-permeability relationship was developed by assuming a fully elastic fractured network of flow path to the wellbore in a hydraulically fractured well. Then, this model was tested by a partially coupled geomechanical simulation in Big Lake field in Cooper basin. The results show that our approach has better predictions than when the permeability is assumed to be constant. By this procedure not only the predictions are improved but also the computational time is reduced.

Handling flow through fractured media is critical for transient pressure and flow analysis in shale gas reservoirs, because gas production from such low-permeability formations relies on fractures, from hydraulic fractures and fracture network to various-scaled natural fractures, to provide flow channels for gas flow into producing wells. This study presents a numerical investigation of pressure and flow transient analysis of gas production from a horizontal, multi-staged well in shale gas reservoirs. A specialized three-dimensional, two-phase simulator is developed and used for this purpose, which incorporates known nonlinear flow behavior in shale gas reservoirs. First we discuss a multi-domain, multi-continuum concept for handling multi-scaled heterogeneity and fractures, i.e., using hybrid modeling approaches to describe different types and scales of fractures from explicit modeling of hydraulic fractures and fracture network in simulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix. Then sensitivity studies of transient pressure responses and flow rates are presented with respect to hydraulic fractures geometry, stimulated reservoir volume (SRV), and natural fracture density. We will also compare the behaviors with two different interporosity flow assumptions, fully-transient and quasisteady state flow. Unlike conventional reservoirs, their difference cannot be ignored due to the extremely low shale matrix permeability and significant gas compressibility. Specifically, we will analyze a field example from Barnett shale to demonstrate the use of results and methodology of this study.

Although existing models for analysing single-phase flowback water production at the onset of flowback in tight oil and gas reservoirs provide estimates of fracture volume, they are not applicable to shale gas reservoirs. This is because flowback data from shale gas wells do not show this single phase region. Instead, they show a surprising trend of immediate gas breakthrough. This paper attempts to (1) understand the fundamental reasons for this early gas breakthrough, (2) develop a representative mathematical model that describes this behaviour and (3) estimate the effective fracture volume and equivalent fracture half-length by history matching the early-time two-phase flowback data. From the diagnostic plots generated from of rate/pressure data of 8 multi-fractured horizontal wells completed in the Muskwa Formation, the gas-water ratio (GWR) plots indicate the presence of initial free gas in the complex fracture network. This conclusion is backed by the imbibition experiments conducted on shale samples collected from the same formation showing the presence of gas-saturated natural fractures. The linear diffusivity equation is solved for early-time two-phase gas/water flow in the hydraulic fractures. The primary drive mechanism at the onset of flowback is initial free gas expansion within the fracture network. Secondary drive mechanisms considered include fracture water expansion and fracture closure. The driving forces are modeled by an effective compressibility term analogous to the total compressibility in conventional multiphase flow formulations. Also, two-phase water/gas flow is handled by an explicitly determined relative permeability function of time. Eventually a new pseudo-time function is defined to account for the changes in gas properties and relative permeability with time. Rate normalized pseudo-pressure versus pseudo-time plots give a straight line when applied to field data, thus the solution can be used to characterize hydraulic fractures in a manner similar to conventional well testing methods.

Prefrac pressure diagnostics, including fracture-injection/falloff sequences, have been used for several years to estimate initial reservoir pressure and transmissibility in unconventional reservoirs. Prior to performing pressure diagnostics, initial or average reservoir pressure is almost always unknown, and many times the purpose of a pressure diagnostic is to determine initial reservoir pressure. As shown by several authors, when a pressure diagnostic falloff exhibits bilinear, linear, or radial flow, the initial or average reservoir pressure can be determined from special plots using straight-line analysis methods. However, correctly identifying the flow regimes during a pressure falloff is often very difficult, and the tendency is to incorrectly apply straight-line analysis methods to data on a specialized plot that often does not correspond to a bilinear, linear, or radial flow regime. In many cases, bilinear, linear, or radial flow will not be observed in any of the falloff data, and valid estimates of initial reservoir pressure and transmissibility cannot be determined using straight-line methods. This paper presents a new type curve analysis method that removes the limitations of conventional after-closure straight- line analysis of pressure diagnostics. Like conventional well test analysis, the new method fits observed pressure data to analytical type curves, and type curve match points are used to determine initial reservoir pressure, transmissibility, fracture half-length, fracture conductivity, and fracture damage. Type curve analysis has proved especially useful for post-frac evaluation of stimulation effectiveness, and has also proved useful in shale reservoirs where it is often difficult to determine if a dilated fracture or fracture network close completely, with no conductivity or retained residual width. Understanding dilation/contraction properties of a shale fracture network can provide important guidance for fracture treatment design and optimization. Type curve analysis has also reduced the amount of shut-in time required to obtain a quantitative estimate of reservoir and fracture properties albeit with increasing uncertainty as shut-in time decreases.

In cemented and cased wells, perforation cluster spacing is optimized based on the type of reservoir fluid, permeability, fracture conductivity, proppant distribution, and associated stresses to place multiple fractures along horizontal wellbores. Specifically, in very low-permeability reservoirs, the requirement for smaller perforation or fracture spacing might not be possible because of the geomechanical interference between fractures. In this case, the commonly used zipper-frac technique can provide a means to create fractures in projects with closer spacing. The benefits of zipper fracs can be maximized by generating proper fracture geometry and properly staggering the perforation/fracture system. This paper reviews and discusses numerical reservoir-modeling results of zipper fracturing that demonstrate the individual or combined effects of the perforation/fracture staggering, comparing these to the fracture length, fracture overlap, fracture conductivity, and/or proppant distribution effects of a conventional completion that does not use the staggered zipper-frac approach. The simulation results are assessed over a wide range of unconventional reservoir permeabilities for both gas and light oil.

Hydraulic fracturing combined with horizontal drilling has been the technology that makes it possible to economically produce natural gas from unconventional shale gas reservoirs. For best performance of fracturing stimulation, hydraulic fracturing designing parameters, such as different proppants, fracturing liquids, and injection rate and pressure, should be evaluated before the oeration in a particular reservoir system. Traditional evaluation and optimization approaches are usually based on the simulated fracture properties along, such as fracture areas. In our opinion, the better methodologyshould be also related to production data from the stimulated wells afterwards, because the enhanced production is the ultimate goal. In this paper, we present a general fully-coupled numerical framework to simulate the hydraulic induced fracture propagation and post-fracture gas well performance. This three-dimensional, multi-phase simulator focuses on: (1) fracture width increase and fracture propagation that occurs as slurry is injected into the fracture, (2) erosion caused by fracture fluid and leakoff, (3) proppant subsidence and flowback, and (4) multi-phase fluid flow through various-scaled anisotropic natural and man-made fractures. Mathematical and numerical details on how to fully couple the fracture propagation part and the fluid flow part are discussed. Fracturing and production operation parameters, properties of the formation, and reservoir, fluid, and proppant properties are all taken into account in this model. The well may be horizontal, vertical, or deviated, as well as open-hole or cemented. This simulator is verified based on benchmarks the literature. We show its application by simulating the fracture network (hydraulic and natural fractures) propagation and production data history matching of field production data in China. We conduct a series of real-data modeling studies with different combinations of fracturing parameters and present the methodology to design fracturing operations with feedback of simulated production data. This unified model aids in the optimization of hydraulic fracturing design, operations, and production.

Tight formations are being developed by drilling in the Midland Basin. Target intervals include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet true vertical depth (TVD). Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the expected pay intervals and are produced commingled. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data pose challenges to making the best decisions. Numerical models can yield insights about drainage patterns and potential interference. This paper reports a case study using a geologic model, hydraulic stimulation models, and a reservoir simulation model to evaluate reduced well spacing impacts on recovered oil and economics. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to data constraints. A reservoir simulation model was then utilized on a sector area of the full model. The sector model was history-matched to early production data and historical type curves. Each well had 10–12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. The paper presents history-matched simulation models that were executed to predict production and economics for 40-acre and 20-acre well spacing cases.

Current industry practice for characterization and assessment of unconventional reservoirs mostly utilizes empirical decline curve analysis or analytic rate and pressure transient analysis. High resolution numerical simulation with local PEBI grids and global corner point grids has also been used to examine complex non-planar fracture geometry, interaction between hydraulic and natural fractures and implications on the well performance. While the analytic tools require many simplified assumptions, numerical simulation techniques are computationally expensive and do not provide the more geometric understanding derived from the depth of investigation and drainage volume calculations. We propose a novel approach for rapid field-scale performance assessment of shale gas reservoirs. Our proposed approach is based on a high frequency asymptotic solution of the diffusivity equation in heterogeneous reservoirs and serves as a bridge between simplified analytical tools and complex numerical simulation. The high frequency solution leads to the Eikonal equation which is solved for a ‘diffusive time of flight’ that governs the propagation of the ‘pressure front’ in the reservoir. The Eikonal equation can be solved using the Fast Marching Method to determine the ‘diffusive time of flight’, which generalizes the concept of depth of investigation to heterogeneous and fractured reservoirs. It provides an efficient means to calculate drainage volume, pressure depletion and well performance and can be significantly faster than conventional numerical simulation. More importantly, in a manner analogous to streamline simulation, the ‘diffusive time of flight’ can also be used as a spatial coordinate to reduce the 3-D diffusivity equation into a 1-D equation, leading to a comprehensive simulator for rapid performance prediction of shale gas reservoirs (Patent Pending, 2013). The speed and versatility of our proposed method makes it ideally suited for high resolution reservoir characterization through integration of static and dynamic data. The major advantages of our proposed approach are its simplicity, intuitive appeal and computational efficiency. We demonstrate the power and utility of our method using a field example that involves history matching, uncertainty analysis and performance assessment of a shale gas reservoir located in East Texas. A sensitivity study is first carried out to systematically identify the ‘heavy hitters’ impacting the well performance. This is followed by a history matching and uncertainty analysis to identify the fracture parameters and the stimulated reservoir volume. A comparison of model predictions with the actual well performance shows that our approach is able to reliably predict the pressure depletion and rate decline.

The Eagle Ford Shale is recognized as the largest oil and gas development in the world, based on capital investment ( Wood Mackenzie 2012 ). Development typically consists of horizontal wells stimulated with multiple hydraulic fracture stages. Almost $30 billion will be spent developing the play in 2013, and optimizing the completion design and spacing of these wells can result in large rewards for the companies involved. This paper presents a pragmatic integrated workflow, used to optimize development and guide critical development decisions in the Black Hawk field, Eagle Ford Shale. Geoscientists, reservoir, and completion engineers worked collaboratively to identify the optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells. Wide uncertainty exists in many key reservoir and completion parameters. Using stochastic realizations from ranges of key properties, uncertainty was reduced using the history matching process. The resulting calibrated reservoir scenarios formed the basis of optimization studies for development drilling and down spacing. Completion design parameters, including fracture stage length, perforation clusters per stage and landing point for the lateral, were evaluated in hydraulic fracture models. The resulting fracture geometries were simulated and the optimum completion design, and well spacing determined for each area. The optimal development was shown to vary by region, due to changing reservoir, fluid and geomechanical properties. The use of multiple subsurface realizations, spanning an appropriate range of uncertainty, was critical to the success of this study. Economic analysis across a range of potential outcomes enabled robust development decisions to be made. As a result of this work, field trials to test proposed changes to the completion have been initiated, and development drilling plans updated to reflect the optimal well spacing for each lease.

In this paper, we present a methodology to predict the performance of horizontal gas wells in unconventional reservoirs using publicly available completion data. Our process combines public domain data with statistical analysis and probabilistic simulation methods to forecast well performance without a detailed reservoir characterization. We have tested our methodology using a 425-well dataset from the unconventional Montney resource play in British Columbia, Canada. We believe this workflow can be applied to other resource plays with similar data. In our SPE Paper 167154 [1], we determined the sensitivity of production performance to completion parameters using multivariate regression analysis on the same 425-well dataset from the Montney formation. We found that the number of fracture stages and the number of perforation clusters per stage were the most influential predictors of well performance. In this paper, we discuss how we combined the regression analysis results with probabilistic methods to predict well performance. The model converts the deterministic regression coefficients into probabilistic distributions to account for parameters not considered in the original regression analysis, including reservoir properties. The results of our study show that by using this model, we can match the range of actual well performance outcomes with a 95% confidence. Considering the importance of shale gas resources to the North American energy supply and the difficulty of characterizing shale gas reservoirs, this methodology offers a distinct advantage by providing a predictive model for well performance without the need for a detailed reservoir characterization. This also could be a beneficial tool to use in scoping studies where high-level, rapid evaluation is required.

Crush resistance has become a key, perhaps even the singular, parameter used in selection of proppant for hydraulic fracture stimulation operations. The API Recommended Practice 19C (RP19C)—which is identical to the ISO13503-2 standard 1 — lays out procedures intended to produce repeatable results. However, repeated measurements in the same lab are inherently noisy and lab-to-lab results often produce crush strength differences of as much as 2k psi. The RP19C is intended to produce reliable and repeatable proppant crush results. However, results from this study show that when compared to other possible methods, the RP19C procedure both increases the noise in the measurement and lowers the crush rating. We describe a series of experiments which provide statistically reliable insight on the effect that loading and handling of the crush cell has on the crush results. The data allow a comparison of five loading methods: the standard RP19C method; the Pluviator; a jarred-cell approach to test the RP19C admonition to avoid "agitating" the cell; a vibratory settling method and a new mechanical loader, designed by the authors. Because two of the loading methods produce statistically significant improvements in crush resistance (specifically the vibratory method and the new mechanical loading device) and because the primary effect appears to be tied to maximizing the packing density, we conclude that the in-situ crush resistance of these proppants may be higher than estimated by the standard test.

Induced fracture complexity maximization, in addition to the primary hydraulic fracture, to improve the recovery efficiency or productivity of gas or liquids in unconventional reservoirs has been accepted and fully implemented by the industry. As a result, stimulation fluids and/or completion strategies have been engineered to maximize induced fracture complexity in many unconventional reservoirs. In typical horizontal completions, induced fracture complexity with sustained conductivity is clearly beneficial for the productivity of nanodarcy (nd) shales, although this might not be a requirement for all unconventional reservoirs, especially tight sands. In some unconventional reservoirs, operators have observed similar productivity in wells with predominantly planar fractures compared to wells that appear to have more complex fractures. This paper, supported by extensive reservoir simulations, aims to develop criteria for situations in which induced fracture complexity and sustained conductivity are required and when they are not. The simulations include a reservoir permeability range of 10 nd to 0.001 md and a complexity or secondary fracture conductivity of 1 to 5 md-ft. The results show that the fracture complexity and sustained conductivity are generally important for reservoir permeabilities lower than 100 nd for gas and 500 nd for liquid-producing reservoirs. Based on these results, an optimized completion strategy is suggested to maximize the productivity or recovery factor (RF) in unconventional gas- and liquid-producing reservoirs.

Wellbore monitoring techniques are proving to be significant in reservoir management and intervention design, particularly in unconventional fields where fluid flow behavior is not very well understood. Distributed temperature sensing (DTS) technology allows for an estimation of zonal flow rates in the entire well as a function of time during hydraulic fracturing, as well as during the production phase. In this work, a novel transient thermo-hydraulic model that includes fluid transport and thermal coupling and simulates fluid flow and temperature in both the wellbore and reservoir is presented. Real DTS data from a hydraulic fracturing operation in a low-permeability basin in west Texas has been inverted using this model. Flow allocation based on the thermo-hydraulic model is presented. It was found that the reservoir heterogeneity, and hence the zonal flow rates, can be accurately obtained based on temperature and pressure data from the well. Most of the steady-state DTS data inversion models are typically applicable to production scenarios, where the transient in temperature has vanished. Injection operations, such as in fracturing where the temperature does not achieve a steady- state during the injection stage, require a transient model that can capture the initial-time effects. Also, some of these models fail to include the Joule-Thomson effect, and this leads to an incorrect flow allocation. The thermo-hydraulic model developed in this work includes both the Joule-Thomson and transient effects. It can be applied to non-reactive fluid injection during stimulation operations, such as matrix acidizing and fracturing. In particular, application of the model for fluid distribution before, during, and post-fracturing provides an estimate of the efficiency of fracturing stages.

In 2014, more than 30,000 wells will be drilled in different unconventional plays across the US. As drilling density increases, chances are these new wells will be located in the vicinity of a producing unit. When the new well is being completed, the pressure depletion around the producing well affects the principal stress regime, creating low stress compartments that attract the majority of the slurry injected. This condition has been studied in the past for vertical wells and results confirmed that the asymmetric propagation of the fracture wings leaves vast sections of the reservoir un-stimulated affecting well performance. This study uses a dataset from the Williston basin to evaluate the impact of this condition in modern horizontal completions. Pore pressure maps from single well models are used to build a multi-well geomechanical model, a numerical fracture simulator is used to understand fracture geometry and quantify wing asymmetry and a multi-well production model is created to estimate the impact in ultimate recovery. Finally, this paper concludes with a series of recommendations regarding completion design and production strategy that can reduce the severity of fracture asymmetry and increase EUR.

A numerical modeling study was performed to investigate fluid recovery following hydraulic stimulation in low matrix permeability formations. A simulator was used, CFRAC, that implicitly couples fluid flow with the stresses induced by fracture deformation in two-dimensional discrete fracture networks. An unstructured mesh was created around the fractures to simulate leakoff and flow in the matrix. Four simulations were performed in which fluid was injected, the wells were shut in, and then fluid was produced back to the surface. The baseline simulation contained a single, linear fracture propagating away from the wellbore. The other three simulations used a stochastically generated network of natural fractures and assumed that as hydraulic fractures propagated through the formation, they terminated when they intersected natural fractures. The termination process created complex, branching fracture networks. The simulations showed that fracture network complexity reduced fluid recovery because the natural fractures, which were not perpendicular to the minimum principal stress, closed at an elevated fluid pressure and created barriers for flow between the wellbore and the open, fluid-filled fractures away from the well. However, if the transmissivity of closed fractures was too low, the fracture network was inhibited from becoming complex, and fluid trapping was not as severe. In the two complex fracture network simulations with lower closed fracture transmissivity, the shut-in pressure transient showed abrupt changes in slope, which were caused by episodic growth of the fracture network due to leakoff of fluid into natural fractures, rapid propagation of opening along the natural fractures, and subsequent initiation of new hydrualic fractures. In practical applications, the observation of abrupt changes in slope during shut-in could be taken as evidence that episodic fracture propagation is occurring, which would imply a complex and branching fracture network. In one of the three complex fracture network simulations, it was assumed that closed fractures had relatively high transmissivity, and abrupt changes in the slope of the shut-in transient were not present, even though a complex fracture network developed during stimulation.

The geomechanical properties of an unconventional reservoir or shale, especially the minimum in-situ stress and fracture gradients, are important for several applications such as mud weight optimization and completion design. Two common methods of direct stress testing are using a wireline formation tester (WFT) with straddle packers and surface-pressure-based fracture injection tests (FITs). Microfracturing was performed at several depths using a WFT in tight clastic and shale oil formations in a well in west Texas. In the same well, microfracturing was also performed using the FIT method, and hence, the two results could be compared. Imaging logs show many drilling-induced fractures in the target intervals, but formation testing with straddle packers did not provide any successful pressure measurements or formation fluid samples because of the low permeability and lack of a natural fracture network in the near-wellbore region. However, fractures were successfully induced in multiple zones by using the WFT microfracturing tool, and the results compare favorably with the geomechanical logs. Downhole quartz pressure gauges used with the microfracturing are very sensitive and can be used to calibrate surface-pressure-based FITs. Microfractures can be induced with less than a few gallons of drilling mud, and the pressure response is observed downhole without any frictional losses or time lag. In addition, the closure time derived from microfracturing is much shorter than the surface FIT-based closure time; however, microfracturing entails additional rig time. In-situ stresses control the orientation and propagation direction of hydraulic fractures. Microfractures are tensile fractures that open in the direction of least resistance. These fractures are also affected by hoop stress in the near-wellbore region, drilling induced fractures, and borehole breakouts. Results indicate that stress gradients, which vary widely across the basin and lithofacies, are controlled by local and regional stresses. The stress gradients derived from microfractures are compared to sonic-log derived gradients and indicate that a symbiotic relation exists in calibrating and quality controlling sonic logs, image logs, and microfracture testing. Intervals with drilling-induced fractures that extend beyond 3 feet tend to give lower stress gradients from microfracture testing and these zones should be avoided for microfracturing. Existing natural open fractures reduce the ability of the WFT tool to seal against the borehole and to create and propagate a fracture in the formation. The location of unaltered formation should be promptly identified for testing prior to entry into the borehole. This may entail having wellsite interpreters as data transmission speeds can pose a constraint while uploading and interpreting image logs offsite. Sonic-log-derived models for stress gradients can be calibrated with pore pressure and overbalance from WFT. Stress gradients generated from microfracture testing can be used to calibrate parameters such as Biot's constant in the sonic stress gradient models derived from poroelastic theory. Ideally, several lithofacies should be targeted for microfracturing to provide a representative stress profile. Imaging logs run after microfracturing can give an indication of the extent and direction of microfractures.

Various methods are used to overcome choking effects in propped fractures to enhance and maintain well productivity (particularly in low-permeability reservoirs). Choking effects can result from permeability damage caused by fracturing gel residues, low-proppant concentrations, proppant crushing from high closure stresses or use of low-quality fracturing sand, or embedment/intrusion of formation materials into the proppant pack. This paper describes the development and field applications of a new well stimulation method for generating stable and highly conductive channels within a propped fracture to help maximize the transport capability of hydrocarbons from the formation reservoir to the wellbore. Extensive laboratory experiments and large-scale testing were performed to evaluate the formation and stability of proppant aggregates and proppant-free channels (PFCs). Proppant-laden slurry (prepared by mixing fracturing sand coated with an agglomerating agent in a gel fluid) and crosslinkable proppant-free spacer fluid were pulsed intermittently to form proppant aggregated masses surrounded by proppant-free gel slugs. Highly conductive channels were formed surrounding the proppant aggregates after crosslinked gel slugs were broken and removed from the propped fracture, leaving behind proppant aggregated masses that supported the closed fracture. Field trials were performed in unconventional and conventional oil formations. Injection pressures of proppant-laden slurry and proppant-free spacer using the pulsing approach were found to be significantly lower than those applied with conventional hydraulic fracturing treatments, indicating this new method helps alleviate the risks of screenout, as the proppant-free spacer sweeps and mitigates the proppant buildup in the near-wellbore (NWB) area. Field results showed production in wells treated with the proppant-free channel fracturing method increased significantly, even using 40% less total proppant, compared to production of offset wells in which conventional fracturing treatments were performed.

In multistage fracturing of unconventional formations such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters simultaneously. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring, and other measurements that several clusters produce below expectations or do not produce at all. This condition is to a degree because stages penetrate zones with stress heterogeneities, and consequently, fractures propagate unevenly from all of the clusters. Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even further to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced fracturing technique has been developed based on a novel composite fluid comprising of degradable fibers and multi-sized particles that diverts the remaining stimulation fluids to understimulated regions of the wellbore. The composite fluid is delivered downhole at high-concentration, to create temporary plugs in clusters already stimulated thereby creating diversion with a minor amount of material. The solids degrade completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The channel fracturing technique ( Gillard et al. 2010 ) was chosen as the preferred fracturing method for use in tandem with the composite fluid. This technique has been reported to increase effective fracture length while reducing risk of screenout with respect to other conventional methods. The new composite fluid was used in a campaign where its effects were monitored with microseismic instruments. A case study presents field experiments where wells from the same pad are fractured in a similar fashion with and without diversion. In one application, with similar water and fluid volumes, the well treated with this technique produced more than 15% per stage than its conventionally treated offset well. The signature of the composite fluid, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells having different characteristics.

Tight oil and shale gas resources produced 29% of total US crude oil and 40% of total US natural gas in 2012 (EIA). Technically recoverable quantities of shale gas and shale oil resources for the US are 665 trillion cubic feet and 58 billion barrels, respectively. Considering the impact of the "unconventional boom" on the economy, it is crucial to understand the production performance of wells to maximize the recovery from shale plays. The latest advances in Rate Transient Analysis (RTA) provide quick yet robust tools to assess the quality of the Stimulated Rock Volume (SRV) and long term performance of the wells by estimating EURs. The most common challenge in history-matching of production in shale gas/oil wells has been the non-uniqueness of the history-matched parameters. A lot of emphasis has been put on estimation of fracture half-length, which is believed to be a primary driver for the performance of shale gas/oil wells. Since linear flow is the main transient flow regime in the early life of a hydraulically-fractured shale gas/oil well, a Rate Normalized Pressure (RNP) versus Square Root of Time plot is the most commonly used diagnostic plot for the performance analysis of the wells. A*sqrt(k) or x f *sqrt(k) parameter groups are reported as a proxy for productivity in hydraulically fractured shale/gas oil wells. Besides having permeability as an unknown, the history-match is also sensitive to net hydraulic fracture height, which is one of the inputs to models that must be specified from other sources of information. This paper presents a novel approach for production performance analysis of shale gas/oil wells, which significantly reduces the non-uniqueness issues that one can have in comparison of performance. Twenty two Eagle Ford Shale wells were analyzed across the trend from lean gas to high-yield condensate to define a workflow that could be applied to other wells in different geologic areas, yet provide consistent comparison of long term performance (EURs).

Oil shale, an organic-rich impermeable rock, is an abundant energy resource in the United States. Because few oil shale deposits occur in shallow formations, application of an in-situ process is necessary for thermal decomposition and subsequent oil and gas production. An earlier investigation indicated that cylindrical or planar in-situ electric heaters were more efficient than flowing steam through created fractures. This study investigates the efficiency of oil shale in-situ upgrading by steam flowing in vertical fractures. There are challenges in the through description of in-situ upgrading process because the kerogen decomposition involves of a series of complex and sensitive reactions, and results a large number of fluid and solid products. Expanding the Flow and Transport Simulator (FTSim) developed by Texas A&M University, we developed a fully implicit capability that describes the decomposition of kerogen in the oil shale and the resulting system changes with minimal simplification and assumptions. The decomposition process is represented by 6 kinetic reactions (resulting 10 components and 4 phases), involves coupled processes of mass transport and heat flow, and accurately accounts for phase equilibrium and phase transition thermodynamics. We applied our simulator to find a successful strategy for hydrocarbon production using steam that flows in vertical fractures created by multistage transverse fracturing in a horizontal (MTFH) well. The simulation of simultaneous heating and flowing provides the system change of oil shale reservoir during in-situ upgrading, and it indicates the necessary condition of successful hydrocarbon production from oil shale reservoir.