Permeability Jail Research Articles

Characterization of the generalized permeability jail in tight reservoirs by analyzing relative-permeability curves and numerical simulation

This study comprehensively characterizes the boundary values of generalized permeability jail in tight reservoirs through relative-permeability curve analysis, numerical simulation, and economic evaluation. A total number of 108 relative-permeability curves of rock samples from tight reservoirs were obtained, and the characteristics of relative-permeability curves were analyzed. The irreducible water saturation (Swi) mainly ranges from 20% to 70%, and the residual gas saturation (Sgr) ranges from 5% to 15% for 55% of the samples. The relative-permeability curves are categorized into six types (Category-I to VI) by analyzing the following characteristics: The relative permeability of gas at Swi, the relative permeability of water at Sgr, and the relative permeability corresponding to the isotonic point. The relative permeability curves were normalized to facilitate numerical simulation and evaluate the impact of different types of curves on production performance. The results of simulation show significant difference in production performance for different types of relative-permeability curves: Category-I corresponds to the case with best well performance, whereas Categories-V and VI correspond to the cases with least production volume. The results of economic evaluation show a generalized permeability jail for Categories-IV, V, and VI, and the permeability jail develops when the relative permeability of gas and water is below 0.06. This study further quantifies the range of micro-pore parameters corresponding to the generalized permeability jail for a tight sandstone reservoir.

A Unified Pore Network Model for Evaluation of Permeability, Relative Permeability, and Sealing Capacity From Mercury Intrusion Measurement

SummaryThis paper presents a new 3D mathematical pore network model for evaluating some important, but hard-to-measure physical properties, including permeability, relative permeability, recovery factor, and sealing capacity from easy-to-measure mercury intrusion data. A 3D pore network is constructed by mimicking the penetration process of mercury based on an idealized pore shape. The pore shape is two frustra of cones connected at their base. A pore orientates in 3D space with an alignment angle to the bedding, which is a function of deformation of the sedimentary rock. Since mercury intrusion measures a 3D pore network and intrudes pores from largest to smallest, a pore size distribution measured by mercury intrusion is itemized into individual pores; a 3D pore network model is then formed by adding pores, one by one from the largest to the smallest, to the pore network. In the process, pores are connected into pore strings along the three orthogonal directions. The properties are derived by modeling fluid flow in the pore strings in a particular direction. Sealing capacity is simply the capillary pressure of the smallest pore of the first three largest orthogonal pore strings of the 3D pore network. Permeability is modeled by applying the modified Hagen-Poiseuille equation, Darcy’s law, energy and mass conservation, and the effect of eddy formation and flow direction change in the pores to the constructed 3D pore network model. Relative permeability is modeled for the imbibition process for two-phase flow based on the below imbibition theory proposed in this paper. Initially, the nonwetting phase exists in large pore strings, and the wetting phase occupies small pore strings. There are always some pores in a large pore string connected with pores of the small pore strings. In the imbibition process, under the differential pressure and capillary pressure, the wetting phase in some small pores invades some large pores filled with the nonwetting phase at the contact to form interfaces. As a result, in these pore strings, the effective pressure drop, which drives the movement of the fluids, is reduced by the capillary pressure of the interfaces. The constructed relative permeability model is a function of viscosity, interfacial tension (IFT), and contact angle of the fluids, and also pressure gradient, which is often overlooked. The developed model has been applied to some mudstone and limestone samples. The modeled sealing capacities of 29 mudstone samples show that a mudstone with a clay content greater than 40% and porosity less than 0.2 would be an effective caprock to oil. The modeled permeabilities of 29 limestone samples show that the model is able to predict limestone permeability within a factor of two in nearly four orders of magnitude range. The modeled relative permeabilities of two limestone samples demonstrate the effect of IFT, contact angle, and pressure gradient on the relative permeability and recovery factor and the capability of the model to simulate a special phenomenon—permeability jail.

Experimental study on the permeability jail range of tight gas reservoirs through the gas–water relative permeability curve

The permeability jail refers to a specific water saturation range in a tight gas reservoir, where almost no gas or water phase can flow effectively. In the process of drilling and fracturing, water saturation rises and falls into the permeability jail. To reduce or avoid falling into the permeability jail in the recovery process, a method for measuring gas–water relative permeability of tight sandstone is established here that considers salt sensitivity, gas slippage effect, stress sensitivity, and high bound water saturation. Then, the permeability jail range was determined to provide guidance and suggestions for field application. Considering a typical tight sandstone as an example, the proposed method was used to expand the measurement range of gas–water relative permeability and observe the permeability jail range, laying an experimental foundation for accurately determining the permeability jail range in a given formation. The Byrnes model can preliminarily predict the permeability jail range with accurate bound water saturation and residual gas saturation. When the permeability jail phenomenon occurs in the core, the larger the permeability is, the smaller the permeability jail range will be; and the larger the porosity is, the smaller the permeability jail range will be. When the permeability jail phenomenon occurs in the tight sandstone reservoir, the damage to the reservoir due to external fluid and solid phased particles should be strictly controlled. The damage is stronger, the permeability and porosity decline, and the permeability jail range is wider. Other gases or solvents can be used as fracturing fluids to minimize formation damage.

Pore-scale systematic study on the disconnection of bulk gas phase during water imbibition using visualized micromodels

When water imbibes into tight rocks, the disconnection of bulk gas phase will significantly impact the performance of gas recovery. In this work, we have conducted a systematic micromodel study on the disconnection of gas phase during water imbibition. Seven types of micromodels were designed that can geometrically mimic basic pore structures of a tight sandstone. Then, we conducted capillary-dominant imbibition experiments and analyzed the effects of pore geometry and pore-throat ratio on the transient evolutions of gas–water interfaces. Our pore-scale results reveal that snap-off and bypassing flows are the two main mechanisms that determine disconnection and entrapment of the gas phase. Moreover, we qualitatively linked the pore-scale two-phase displacements to the core-scale “permeability jail” phenomenon (i.e., nearly immobile of non-wetting and wetting phases across a wide range of saturation values). Our study will enrich the knowledge of entrapment behaviors of the gas phase during water imbibition into tight formations.

Influence of different shut-in periods after fracturing on productivity of MFHW in Duvernay shale gas formation with high montmorillonite content

Drilling multi-stage fracturing horizontal wells (MFHWs) is the most effective way to unlock shale gas resources economically. This paper investigates the influence of different shut-in periods after fracturing, and their impact on the productivity of MFHWs in the Duvernay shale gas formation. This western Canadian formation has a high montmorillonite content which impacts the findings. A Duvernay shale core with high montmorillonite content was used to study gas–water relative permeability. Unsteady state tests were conducted under a variety of soaking times. The experiments demonstrated that the Permeability Jail for relative permeability curves exist in a water saturation range of 60% – 80%. This phenomenon partly explains the rapid gas production decline and a long period of little water production during the formal production in a typical shale gas well. Clay in shale mainly contains illite and montmorillonite. They have surface hydration, which occurs fast enough to cause induced fractures that improves the seepage capacity initially when the core is soaked. As the soaking time prolongs, there is an osmotic hydration expansion of the montmorillonite blocking pore throats and a corresponding reduction of the seepage capacity. The relative permeability increases during the soaking days one to four. After four soaking days, relative permeability begins to slowly decrease over time. Study calculations found that 61.4% – 75.6% of the total fracturing fluid filtrates into the formation. During days one to six of the soaking, the filtration volume increases significantly due to a high initial pressure in the fractures after pump shutdown. After seven days of soaking, the filtration velocity decreases due to the pressure drop and the difficulty of compression caused by more and more fluid in the formation. Based on reservoir simulations of 600 days, the relative permeability value in the near fracture zone and the cumulative gas production are the greatest on day four of the shut-in. The longer the shut-in period, the greater the initial water production rate and cumulative water production reaching a maximum at four shut-in days. In this Duvernay area with high montmorillonite content, the optimal shut-in period after fracturing was determined to be four days.

RESERVOIR SIMULATION STUDY ON THE PERMEABILITY JAIL'S EFFECT DURING TIGHT GAS PRODUCTION

Permeability jails in tight rocks can lead to severe impacts on hydrocarbon production. Although this is a significant problem, the understanding of the influence of the permeability jail on tight gas production is limited. Few methods to avoid the permeability jail's effect have been reported. In this work, the permeability jail's effect on tight gas production was studied using the reservoir simulation method based on two real tight gas wells. First, the gas−water flow resistance in porous media was analyzed to calculate the critical pressure drop, which can be used to find the location of the permeability jail in tight gas reservoirs. Then, the location of the permeability jail was investigated using a reservoir pressure profile. Finally, two real wells were modeled to study the influence of the permeability jail on tight gas production by: (1) analyzing the location of the permeability jail; (2) evaluating the permeability jail's effect and well performance; and (3) optimizing the bottomhole pressure to reduce the permeability jail's effect. The results indicate that the permeability jail is located in the zone away from the wellbore and hydraulic fracture faces. About 64.5% of the gas production rate is lost due to the permeability jail at the beginning of production. However, this effect starts to be relieved when production lasts for 182 days. A low bottomhole pressure tends to reduce the impact of the permeability jail. To avoid loss of well productivity, the value of the bottomhole pressure necessitates careful optimization.

Permeability jail for two-phase flow in tight sandstones: Formulation, application and sensitivity studies

Permeability jails in tight rocks correspond to saturation values where no phase is mobile. This can lead to severe impacts on hydrocarbon production. However, although this is a severe and significant problem, there is a limited understanding of the mechanisms behind the concept of a permeability jail, its dependence on pore size distributions, saturations and pressure. In a previous work, we describe a model to compute the flow resistance during two-phase flow in tight rocks. In this paper, we extend our work to propose a model for the permeability jail in tight rocks to calculate relative permeabilities during two-phase flow. The rock is assumed to be characterized by a bundle of capillary tubes with non-uniform radii where the fluids are present as discontinuous phases. The pore-scale flow resistance is calculated which takes into account the capillary pressure induced by the Jamin effect as well as the water and gas viscous forces. The model is validated by experimental data of gas-water relative permeability tests and Nuclear Magnetic Resonance (NMR) experiments on tight cores from the Sichuan Basin in Southwest China. According to the model, the pressure drop between the inlet and outlet sides of the core should be higher than the maximum capillary pressure to maintain flow during the experiments. We also observe that the relative permeability curves are pressure-sensitive. An increase in the pressure drop leads to a reduction of gas relative permeability and an increase of water relative permeability. However, the influence of this pressure drop is somewhat limited. Once trapped in a permeability jail, fluids generally cannot regain flow capability by changing the pressure drop over a small range of values. This necessitates a careful consideration of the factors contributing to the permeability jail in order to avoid loss of well productivity.

Predicting flow properties in diagenetically-altered media with multi-scale process-based modeling: A Wilcox Formation case study

Two approaches to capture the complex texture of Wilcox sandstone samples in a pore-scale model are employed: a process-based method and an image-based method. In the process-based method, petrographic analyses from transmitted light microscopy are used to infer the diagenetic history of the rock. Key steps in the diagenesis are quantitatively followed using a multi-scale pore-network modeling method to reconstruct the porous medium at different times in its history, including the final state. Further information about pore sizes is gathered from scanning electron microscopy and nitrogen adsorption hysteresis measurements. The ability to incorporate texture information of each diagenetic stage of a tight gas sandstone into a predictive multi-scale pore-network model is a novel aspect of this work. In the image-based method, a micro-CT image of the sample is acquired and a pore-network model is extracted based on skeletonizing the resolvable pore space and mapping clusters of micropores to the unresolved porous areas. The paragenesis of the formation was not captured using the image-based method since sufficient details of its history could not be extracted. The process-based and image-based methods produce comparable drainage capillary pressure curves. While the drainage relative permeability curves in both methods display permeability jail effect, they considerably differ from each other quantitatively. The process-based method produced a higher porosity and permeability compared to the image-based method which is potentially due to the lower degree of its disorder. High uncertainties in the petrophysical properties of tight gas sandstones is a costly challenge in their reservoir development. Our work provides insights into the effect of pore texture from different scales on rock fluid properties. Furthermore, the methods demonstrated in this work can be pursued to extrapolate tight gas sandstone petrophysical properties between wells and throughout paragenetic sequences. • An algorithm for the inclusion of oversize pores in process-based modeling is introduced and implemented. • A comparison of process-based and image-based multi-scale pore-network modeling methods in predicting several petrophysical properties is conducted. • Sedimentary rock fragments and dissolving feldspars can be crucial for fluid flow for the Wilcox Formation. • Permeability jail effect is observed during primary drainage using both methods.

Effectiveness and time variation of induced fracture volume: Lessons from water flowback analysis

Characterizing the induced fracture network is crucial for evaluating and optimizing fracturing operations and for forecasting hydrocarbon production. In our previous paper [1], we developed a closed-tank material balance model to estimate effective fracture volume using rates and pressure data measured during early-time water flowback. In this paper, we extend this model to an open-tank model to estimate fracture-matrix interface area using rates and pressure data measured during late-time water flowback. We verify the proposed model against a 2D numerical model solved by a commercial software, and demonstrate the application of the proposed model to an eight-well pad completed in the gas shales of the Horn River Basin. Finally, we conduct a comparative analysis to investigate the time variation of effective fracture volume during water flowback. The results show that up to 30% of the effective fracture volume is lost due to pressure depletion and fracture closure during early-time water flowback. The rate of fracture volume reduction decreases during late-time flowback when gas from the matrix kicks into the fracture network and provides sufficient pressure support. However, the estimated fracture-matrix interface area is relatively low and cannot be explained by the estimated fracture volume. This result suggests that although a large fracture network is created by hydraulic fracturing operations, only a small fraction of the fracture network receives gas influx from the matrix. Overall, the results suggest that a large fraction of the fractures induced in gas shales does not contribute to hydrocarbon production due to fracture closure, permeability jail effect, and water blockage.

Relative permeability estimates for Wolfcamp and Eagle Ford shale samples from oil, gas and condensate windows using adsorption-desorption measurements

Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate relative permeability of aqueous and hydrocarbon phase in shales by processing the low-pressure nitrogen adsorption-desorption isotherm measurements. The interpretation method is applied to 35 samples from various maturity windows of Eagle Ford and Wolfcamp shale formations. The method assumes that effective medium theory, percolation theory, and critical path analysis can quantify the biphasic fluid transport in shales.The relative permeability curves were estimated for samples collected from 100ft interval in Eagle Ford gas window, 30ft interval in Eagle Ford oil window, and 60ft interval in Wolfcamp condensate window. Although the samples exhibit large variations in organic content, pore connectivity, range of connected pore network, and pore complexity, the relative permeability curves estimated for these samples exhibit relatively similar trends. Samples from gas and oil windows were low temperature plasma ashed to study the effects of removal of organic matter on relative permeability and pore network characteristics. The relative permeability of aqueous phase decreases sharply with decrease in water saturation, whereas the relative permeability of hydrocarbon phase decreases at a relatively slow and constant rate with increase in water saturation. Relative permeability estimates for the shale samples explain the low water-cut during hydrocarbon production, absence of correlation between hydrocarbon production decline and the increase in water production, and the existence of permeability jail in shale reservoirs.

Pore-scale analysis of flow resistance in tight sandstones and its relationship with permeability jail

In tight sandstones from the Sichuan basin, permeability jail is observed. Because tight sandstones in the Sichuan basin have a high water saturation, gas and water exist as discontinuous phases at the pore scale, which could be the cause of permeability jail. In this paper, flow resistance in tight sandstones was studied, and its relationship with permeability jail was investigated. First, a model to characterize flow resistance in discontinuous phase flow was proposed. The model was based on a bundle of capillary tubes with non-uniform radii, which took the capillary pressure difference induced by the Jamin effect, water viscosity force and gas viscosity force into account. Then, a gas-water relative permeability test and NMR experiment were conducted to verify the model. Finally, the flow resistance at a series of water saturation points was calculated to study the relationship between flow resistance and permeability jail. The results show that discontinuous phase flow is affected by the Jamin effect, which induces permeability jail because the capillary pressure difference reaches the maximum and leads to a very high flow resistance in permeability jail. Capillary pressure difference falls, however, when water saturation is outside of permeability jail, which contributes to the drop of the flow resistance and helps recover the flow capability.

Reconciling flowback and production data: A novel history matching approach for liquid rich shale wells

The recent downturn in petroleum prices poses a challenge to the oil and gas industry and in particular to the development of shale assets. This unfavorable economic situation calls for improved reservoir characterization and modeling that are necessary for the optimization of well design and cost. Current rate transient analysis (RTA) techniques are well-suited for the reservoir characterization of dry shale gas wells. However, they have limited accuracy for the more profitable liquid rich shale (LRS) wells. For example, RTA does not accurately model three-phase flow of gas, water, and condensate that can occur in the reservoir. Further, application of RTA typically ignores post-fracturing water flowback data that can be analyzed for important information pertaining to hydraulic and secondary fractures. In this work, the reservoir of LRS wells is characterized by simulating and history matching the three-phase flow of early flowback and long-term production.In this work, characterization and history matching are performed by utilizing a novel procedure that includes an equation of state (EOS), a compositional reservoir simulator, and a multi-objective optimization (MOO) algorithm. In addition, the simulation approach incorporates various water trapping mechanisms that are necessary to reproduce the water production rate trends. The procedure minimizes the misfit between observed and simulated production data. It starts by first tuning the EOS to a surface recombined sample. Then, a triple-porosity (i.e., hydraulic fracture, secondary/natural fracture, and matrix porosities) simulation model is applied that utilizes the multiple interacting continua (MINC) method and accounts for permeability jail, pressure-dependent permeability, capillary pressure, and gravity segregation. Finally, an MOO algorithm is used, namely the fast nondominant sorting genetic algorithm (NSGA-II), to solve the misfit minimization problem.The introduced procedure has a number of advantages. One advantage is the simultaneous matching of flowback and production data which improves rock and fracture characterization. Another advantage is the utilization of MINC combined with logarithmic gridding that can model transient flow in a triple porosity system. Moreover, it can model different fracture shapes by adjusting a shape factor parameter. In addition to these, the use of MOO does not require predetermined weights unlike the aggregate function approach. In this article, detailed description of all the steps of the history matching workflow are presented, and its applicability demonstrated with a field example from the Montney Formation.

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Experimental study of the stress dependence of the absolute and relative permeabilities of some tight gas sandstones

Connected porosity and dry gas permeability at 5MPa hydrostatic stress have been measured for thirteen tight gas sandstone samples originating from a Rotliegend sandstone reservoir in Germany. The samples have then been preserved into hermetic chambers at fixed relative humidity (RH) values, until mass (and water saturation level) stabilisation. This allows a first characterisation of pore size distribution showing that most of the pore network is constituted with pores with entrance radii greater than 50nm. The relative gas permeability was then measured for different water saturation and hydrostatic stress (up to 60MPa). The analysis of the results has allowed us to identify the limiting conditions (water saturation and hydrostatic stress) for the apparition of a hydraulic cut-off, also called the “permeability jail”. Dry gas permeability at low confining pressure (5MPa) has appeared to be a good indicator of the sensitivity of a sample to both hydraulic stress and liquid saturation. This gives an efficient tool to predict the global behaviour of the gas reservoir despite its heterogeneity with a single gas permeability measure.

Damage Mechanisms in Unconventional-Gas-Well Stimulation - New Look at an Old Problem

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142479, ’Damage Mechanisms in Unconventional-Gas- Well Stimulation - A New Look at an Old Problem,’ by Josef Shaoul, SPE, StrataGen Delft; Lars van Zelm, SPE, Delft University of Technology; and Hans J. de Pater, SPE, StrataGen Delft, prepared for the 2011 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 31 January- 2 February. The paper has not been peer reviewed. After fracture stimulation, production often increases slowly instead of showing an early transient. This condition indicates either a severe reduction in fracture conductivity or reservoir damage. Little agreement exists about the most likely damage mechanism. New ideas were proposed that may better explain the behavior commonly observed in actual production data. These ideas include “permeability jail” in which relative permeability indicates that water and gas are both immobile at a given saturation, small-scale reservoir heterogeneity, and stress-sensitive matrix permeability at high drawdown. These effects on post-fracture production from an unconventional (0.001-md) gas well were studied by reservoir simulation. Realistic assumptions about proppant-pack cleanup showed a relation of poor cleanup and short effective fracture length to a reduction in contacted permeability-thickness (kh) and to connected reservoir volume. Simulation results showed 50% reduction of production in the first year(s) caused by these effects in unconventional reservoirs. Introduction Worldwide rising gas demand is creating opportunities to exploit low-permeability gas reservoirs outside North America, where a long history of tight-gas-reservoir development exists. In the absence of open natural fractures, economic development of tight gas reservoirs is possible only through the use of hydraulic fracturing, in either vertical or horizontal wells. Production enhancement for any well, whether oil or gas, can be simulated by use of combined reservoir and fracture simulators. Generally, the well-productivity increase can be calculated to a certain degree. For tight gas wells, improved well productivity often is overestimated by simulation programs that use fracture characteristics estimated from fracture-simulation software. Several factors may result in unrealistic production forecasting. In tight reservoirs, it is very difficult to measure kh and reservoir pressure, which are needed for basic flow calculations and are crucial for evaluating stimulation success. The problem arises because of the long time required to measure these parameters in post-fracture well tests. Prefracture-treatment well tests also are time consuming, but have the further problem that it is difficult to know the height of the flowing zone, and it is not desirable to perforate the entire interval in a well that is going to be fracture stimulated. An additional problem in tight gas reservoirs is evaluating the performance of the propped fracture to optimize the stimulation design. Estimating productivity after stimulation requires use of estimated values for fracture dimensions (length, width, and height) and fracture conductivity, all of which are difficult to quantify from well-test or production data without an accurate estimate of the kh. Fracture diagnostics can provide an indication of the created height and length, but reveals nothing about the effective producing-fracture length or height. Estimating kh from diagnostic injection tests is possible, but this method suffers from not knowing the height of the formation being investigated.

Damage Mechanisms in Unconventional-Gas-Well Stimulation—A New Look at an Old Problem

Summary After fracture stimulation of a tight gas well, production often rises slowly instead of showing an early transient. This indicates either severe reduction in fracture conductivity or reservoir damage. There is still no agreement in the industry about the most important damage mechanisms. Work performed by Pratts and Holditch in the 1970s showed that fracture-face damage from filtrate invasion is unimportant unless there is permeability damage in the invaded zone of at least 99%. New ideas have been proposed that may better explain the behavior commonly seen in actual tight gas well production data. These ideas include relative permeability with water and gas both immobile at a given saturation ("permeability jail"), small-scale reservoir heterogeneity, and stress-sensitive-matrix permeability at high drawdown. Experience from the field has been contradictory. Sometimes no water is produced back, but gas production does not appear to suffer. In other cases, the gas rate is significantly lower than expected, but significant fracture fluid is recovered. With the inherent coupling of fracture length and permeability in well-test interpretation and the practical impossibility of achieving radial flow in tight-gas reservoirs with large fracture lengths, it has been difficult to prove any theory about the cause of poor performance from tight gas fracture treatments. This paper shows simulation results of a number of damage effects on post-fracture production from an unconventional (0.001-md) gas well. Furthermore, realistic assumptions about proppant-pack cleanup show a connection not only between poor cleanup and short effective fracture length, but also reduction in contacted kh and connected reservoir volume. New reservoir-simulation results are presented that show a 50% reduction of production in the first years because of these effects in unconventional reservoirs.