Three-point-bending and double-notch shear experiments are modeled using a continuum damage mechanics approach, and an explicit fracture mechanics approach, for both homogeneous and heterogeneous rocks. The local damage approach uses the Mazars isotropic damage model. In the explicit fracture simulations, fractures are represented as explicit surfaces within a threedimensional unstructured mesh comprised of isoparametric quadratic tetrahedra and quarter point tetrahedra. Heterogeneities in strength, stiffness and toughness are introduced in a random manner within ±50% of the average values. A characteristic length is used to define the size of element clusters having uniform properties. Both approaches are used to evaluate the influence of material heterogeneity on crack propagation and interaction. Both models reproduce well the experimental results for homogeneous rocks. While in the damage model the mesh is fixed and refined globally, the discrete approach only requires refinement around the fracture tips. In the three-point-bending and double-notch shear simulations, the damage mechanics approach is more realistic in that it leads to rougher crack surfaces. However, the fracture mechanics model predicts lower curvature of the fracture, which better corresponds to experimental observations. Both approaches predict that the presence of heterogeneities seems to diminish fracture interaction.
Various continuous and discrete numerical models have been proposed to model crack growth in homogeneous materials. However, many materials, such as concrete, rocks, and other quasi-brittle materials, contain heterogeneities, which may affect the growth of fractures (Figure 1).
Damage models, derived within the general framework of continuum damage mechanics, are often used to reproduce the effects of stiffness degradation, without explicitly representing discrete fractures. Models for quasi-brittle damage include micromechanical models, as well as isotropic and anisotropic empirical models. Micromechanical damage models are the most advanced, in that they model microscopic phenomena responsible for the evolution of damage through first-order principles (Krajcinovic, 1986). They are therefore very useful for understanding rock failure. However, they are computationally demanding to implement.
We use here a fully hydraulically-mechanical coupled, 3-D model (Damjanac and Cundall, 2014) to simulate fault reactivation during a hydraulic fracturing treatment. Synthetic seismicity from the model helps quantify seismic energy released by the slippage on the fault. The model is based on a case study in the Horn River Basin by Snelling et al., 2013a. The multi-stage hydraulic fracture model is able to reproduce seismic deformation characteristics observed in field data. Results show that even stages distant from the fault have an influence on the slippage on the fault with a delayed effect. If the first injection stage is the closest to the fault, a large area will be slipping. Successive stages will have a lesser impact due to stress shadowing. If the first stage is farthest from the fault, then slippage on the fault will be gradual, reducing the amount of seismic moment release in a short period of time. This model can be used as a framework to examine the impact of other geomechanical characteristics or other operational factors, which could help establish best practices to mitigate seismicity when faults begin to be active.
Induced seismicity has become a concern for hydraulic fracturing operations in British Columbia and Alberta, Canada. Seismic monitoring is now mandatory for stimulation of two shale formations in this region. The challenge of hydraulic stimulations in areas prone to induced seismicity remains because mitigation can only be achieved with a good understanding of the underlying mechanisms linking multi-stage hydraulic fracturing operations and induced seismicity.
Geomechanical modeling is the best way to understand this link because it allows investigation of the interactions between multiple hydraulic fractures by modeling different injection scenarios and assessment of the sensitivity to different parameters. Many authors have proposed models to investigate induced seismicity (for instance, Goertz-Allmann and Wiemer, 2013; Rutqvist et al., 2013). Most find a strong correlation between pore pressure increase and areas where large magnitude events occur. The models indicate that the increase in pore pressure is caused by the hydraulic fracture following fluid injection.
None of these models can produce synthetic seismicity for quantitative comparison with recorded seismicity. The multi-stage hydraulic fracture model presented here is based on a fully hydraulically-mechanical coupled, 3-D model (Damjanac and Cundall, 2014) which produces synthetic seismicity, which can help quantify the seismic energy released by slippage on faults (Zhang et al., 2015).
The use of cemented paste backfill (CPB) in the mining industry has increased over the past two decades. A comprehensive understanding of the stiffness development of CPB during early binder hydration stages has great impacts on the safety and economy of mines. Ultrasonic wave velocity measurements were performed to characterize the effect of relative humidity (RH) conditions and binder content on the stiffness development of CPB. In this paper the evolution of degree of hydration (DOH) is investigated for CPB with binder contents of 3% and 5% at different RH conditions to study the impact of cement hydration on stiffness development. An insight is presented on the development of shear wave velocity (Vs) with the ongoing hydration process during the first week after mixing. Developing self-desiccation suction in sealed samples was measured. The lack of significant early restraint by the paste to volume change resulted in the delay of the evolution of significant suction forces until high DOH is reached. The study concluded that low cement concentrations results in delaying the formation of solid paths and stiffness development. Therefore, changes in shear stiffness of the CPB and self-desiccation suction are not proportional to changes in DOH.
Cemented paste backfill (CPB) has been increasingly used in the mining industry over the past two decades. Confidence in cemented paste backfilling systems has been increasing as it has the advantage of easy transportation to underground openings, rapid rates of backfilling, increased ore recovery, less water drainage concerns, and the environmental benefits of diverting tailings from surface storage. A comprehensive understanding of the strength and stiffness development of CPB during early binder hydration stages has a great impact on the safety and economy of mines. In particular, it helps to achieve safe and economic barricade designs and to optimize the backfilling process which impacts the scheduling of mining activities. Strength and stiffness development of CPB are believed to be mainly influenced by two factors, the binder content and type; and the curing relative humidity (RH) conditions. One of RH bounding conditions is when free water is available to compensate for pore water consumption ensuing cement hydration. The other bound is when CPB is left to air-dry. Stiffness development in CPB at both bounding RH conditions is investigated by studying the ongoing changes in ultrasonic wave velocities during the first week of curing by Galaa et al. (2011). Wave velocity measurements to characterise stiffness development of CPB was practiced in several studies such as Ercikdi et al. (2014), Yilmaz et al. (2014) and Yilmaz and Ercikdi (2015). In the area of cement and concrete research, ultrasonic wave velocities have been used to assess the hydration process and strength development by many researchers (e.g. D'Angelo et al. 1995, Boumiz et al. 1996, Chotard et al. 2001, Akkaya et al. 2003, Abo-Qudais 2005). Moreover, the effect of RH curing conditions in the context of strength assessment and/or autogenous shrinkage prediction is extensively studied in the concrete area (Molina 1992, Jensen and Hansen 2001, Lura et al. 2002). However, the water to cement (w/c) ratio in CPB is extremely higher than what is normally used in concrete. Consequently, various factors are found to be of influence on cement hydration in concrete and may not have the same level of significance in the case of CPB. Galaa et al. (2011) concluded that RH has a more significant effect on CPB than that of the binder content. In the current study, the degree of hydration is measured for identical samples at the same RH conditions in Galaa et al. (2011) in order to further investigate the conclusion drawn by the mentioned study. In addition, another RH condition is studied where samples are sealed, evaporation is neither allowed, nor free water supply is available.
Chen, Gang (State Key Laboratory of Petroleum Resources and Prospecting China University of Petroleum) | Jin, Yan (State Key Laboratory of Petroleum Resources and Prospecting China University of Petroleum) | Li, Qinghui (Ideal Oil & Gas Connections, Inc) | Li, Lingling (Korla Research Institute of BGP) | Zhou, Bo (PetroChina Tarim Oil Company) | Chang, Yang (China University of Petroleum) | Zhang, Yayun (China University of Petroleum)
This paper analyzes the stress state of vertical wellbore formation in radial flows: phase, flow model and crustal stress. Also collapse volume is studied based on the Mohr-Coulomb criterion. Define a critical collapse condition: the stress state of northern adjacent rock on the wellbore satisfies Mohr-Coulomb criterion. While the collapse of a gas reservoir in Darcy flow, Darcy-Forchheimer flow or accelerating flow will continue to develop in the near-well formation after the stress of adjacent rock reaches certain conditions. The collapse of a gas reservoir in accelerating flow is more liable to develop in near-well formation and the adjacent rock in this kind of flow is the first to reach its critical collapse condition. However, under the dual effect of non-uniform stress field and accelerating flow, collapse may exist in the maximum horizontal stress direction when the stress of adjacent rock reaches its critical collapse condition. Besides, the critical collapse radius corresponding to maximum horizontal stress is likely to be the largest. And computational formula of collapse volume is given in this paper.
When reservoir fluid flows into the wellbore, the pore pressure decreases all the way from the outer boundary to borehole wall . Due to the interaction between fluid and fluid-saturated porous rock, changes in pore pressure will lead to changes in the formation wall stress and the effective stress, which may lead to the borehole instability . Pore pressure gradient of near-wellbore formation corresponding to different flow models in gas reservoir development and testing is various, especially for overpressed gas reservoir. Accelerating effect should be considered in the flow model when flow velocity is large enough. While pore pressure gradient of near wellbore formation in accelerating model is nonlinear and may even be infinite. And the mass flow rate of the fluid has a maximum value [3-5], which will change the effective stress state of near-wellbore formation rock.
During the process of gas reservoir development and testing, adjacent rock is influenced by Darcy flow and non-Darcy flow, the phenomenon of formation sanding has been studied using plastic Coulomb yield criterion and tensile failure criteria, but accelerating effect and collapse volume calculation have not been considered yet [6-9]. Research of compressible fluid showed that there exist blocking flow and infinite pore pressure gradient in the flow model with accelerating effect, however, borehole collapse is not involved [10-13]. Jin Yan et al.  studied radial stress of adjacent rock of accelerating flow; they concluded that when the pore pressure gradient is very large, the effective radial stress may be tensile stress. Still circumferential stress analysis and collapse volume calculation were not taken into account.
The analytical poroelastic solutions for an inclined wellbore drilled through an N-porosity N-permeability porous medium were derived, taking into account the mudcake buildup on the wellbore wall. To extend the application of this general solution, a triple-porosity porous medium is studied to illustrate the pressure and stress distributions around the wellbore. Moreover, the stress cloud approach is presented to visualize the wellbore failure potentials and the Drucker-Prager criterion is applied to analyze wellbore shear failure. Each set of porosity is found to significantly influence the stress clouds at the wellbore wall and the mudweight window. Comparison analysis shows that the single porosity simulation predicts the widest mudweight window, followed by the dual-porosity simulation, and then the triple-porosity simulation. Compared to the single porosity case, the dual- and triple-porosity simulations predict 8.0% and almost 15.0% higher collapse mudweights, respectively. Mudcake also plays an essential role in the wellbore stability. Its effect could be to shift down of the stress cloud and therefore decrease the wellbore failure potential. Mudweight window is also found to be sensitive to mudcake thickness and permeability, which clearly shows that mudcake effects should be taken into account.
The poroelastic solutions for an inclined wellbore have played an essential role in the wellbore stability analysis for drilling through a fluid-saturated porous medium. The wellbore stability is severely affected by the time-dependent poroelastic responses of the fluid-saturated porous medium, such as the evolutions of stresses and pore pressure around the wellbore which might lead to time-delayed failure (Cui et al. 1997; Abousleiman et al. 2000). Early analyses of the time-dependent stresses and pore pressure responses after excavation were presented by Carter and Booker (1982) who gave the analytical solutions for a circular tunnel excavated in a fluid-saturated medium. Detournay and Cheng (1988) derived the analytical solutions for a vertical wellbore under non-hydrostatic stress field and showed that shear failure could be initiated inside the formation rather than on the wellbore wall. The complete analytical solutions for an inclined wellbore drilled through an isotropic fluid-saturated porous medium was given by Cui et al. (1997). Later, the solutions were generated to account for material transverse isotropy (Abousleiman and Cui 1998) and time-dependent pore pressure and flux boundary conditions (Ekbote et al. 2004). For a naturally fractured fluid-saturated rock formation, using the dual-poroelastic formulation, Wilson and Aifantis (1982) presented the analytical solutions for a vertical wellbore under hydrostatic state of stress and Li (2003) for a vertical wellbore under non-hydrostatic state of stress. Abousleiman and Nguyen (2005) derived the complete analytical solutions for an inclined wellbore drilled through a naturally fractured rock formation and subjected to three-dimensional state of stress. Dual-porosity simulation was found to predict narrower mudweight window than single porosity simulation (Nguyen and Abousleiman 2009; Nguyen et al. 2009). Analytical solutions were also derived for inclined wellbore problem accounting for chemo-electrical and thermal effects which are found to be crucial in wellbore stability analysis (Ekbote and Abousleiman 2005; Ekbote and Abousleiman 2006; Nguyen and Abousleiman 2010).
Recent observations suggest that the presence of frictionally weak minerals in a majority frictionally strong matrix may explain the reduced strength and instability in faults. Experimental results on synthetic fault gouges using a mixture of a frictionally strong phase and a frictionally weak phase indicate that the fault can be weakened by even a small amount of frictionally weak minerals. These frictionally weak minerals weaken the fault by either acting as weak spots/clusters or as a through-going weak layer in the bulk gouge. A two-dimensional Distinct Element Method (DEM) numerical model using the Particle Flow Code 2D (PFC 2D) is developed to investigate the effect of frictionally weak minerals on the bulk shear strength of fault gouge. Mechanical response of particles is modeled using a linear-elastic contact model and Coulomb's friction law. Numerical direct shear experiments were performed on homogeneous mixtures of weak and strong mineral particles and also on heterogeneous mixtures consisting of a frictionally weak layer sandwiched in frictionally strong minerals. The weight percentage (wt%) of the frictionally weak mineral in the homogeneous mixtures and the relative thickness of the frictionally weak mineral layer in the heterogeneous mixtures are adjusted schematically to obtain the weakening regime of the bulk shear strength. A transition from high to low residual coefficient of friction is observed. Specifically, for homogenous mixtures a sharp drop of bulk shear strength is observed with 25% of frictionally weak mineral presented in the mixture, and a dominant influence occurs at 50%; for heterogeneous mixtures, noticeable weakening is shown at a relative weak layer thickness of 0.05, and a dominant influence quickly follows at a relative thickness of 0.10. The observed weakening regime matches well with previous lab results using talc/quartz mixtures.
In nature, tectonic faults tend to slip at much lower resolved shear stress than the stresses inferred from rock mechanics experiments (Engelder et al., 1975; Dieterich, 1978; Marone et al., 1990). Explanations to this difference between lab observations and natural phenomenon include low effective stress, elevated pore pressures (Rice, 1992; Faulkner and Rutter, 2001) and dynamic weakening in which friction decreases above a threshold slip rate (Melosh, 1996; Di Toro et al., 2006; Ampuero and Ben-Zion, 2008). Recent field observations of the San Andreas fault (Moore and Rymer, 2007) and an exhumed low angle normal fault in Italy (Collettini et al., 2009a, 2009b) show that the weakness of natural faults can be explained by the presence of talc; a frictionally weak mineral. Earlier experiments using synthetic mixtures of salts and muscovite/kaolinite (Bos and Spiers, 2002; Niemeijer and Spiers, 2005, 2006) showed that weakening can occur with as low as 10% of frictional weak minerals. The shear strength of a fault greatly depends on its mineralogical composition (Ikari et al., 2011; Fang et al., 2015). Shear experiments using mixtures of talc and quartz sand (Carpenter et al., 2009) suggested that in order to weaken the composite gouge, 30%-50% frictional weak mineral is needed. However, there were only 2-3 wt% of talc presented in these weak faults which is surprisingly less than the previous suggestions. The difference can be explained by the generation of a through-going localization zone during dynamic shearing, which greatly weakens the fault. This strong weakening effect of frictionally weak mineral in a majority frictionally strong matrix derives a question of how much the frictionally weak mineral in weight percentage (wt%) is needed; and in terms of localized weakening effect, how thick the weak localization zone is enough to weaken the fault. Experiments have been conducted on synthetic gouge consisting of quartz sand as a strong phase and a through-going talc layer as a weak phase (Niemeijer et al., 2009; Moore and Lockner, 2011). The findings suggest that the frictional strength of the sample gouge decreases systematically with the increase in thickness of the talc layer, two critical values were proposed for a starting point of weakening relative to pure quartz sand and weakening domination point relative to pure talc, Additionally, findings suggest that the permeability evolution of fractures is likely linked to such mineralogical properties (Ishibashi et al., 2015).
Reservoir depletion results in changes in effective stresses, which may lead to significant changes in reservoir permeability. These changes are associated with matrix compaction, fracture closure and potential slip. A depletion-induced increase in effective stresses often leads to a decrease in permeability. However, the opposite is observed to happen in some fractured gas reservoirs with an organic rock matrix that exhibits strong sorption-mechanical coupling. During depletion, an adsorbed portion of the gas desorbs from micropores resulting in shrinkage of the organic components in the rock matrix, effective stress relaxation and a potential increase in fracture permeability. The objective of this study is to develop a reservoir simulator with a full mechanical coupling accounting for sorption-induced change of stresses. This paper aims to estimate the influence of the parameters affecting reservoir permeability and to predict its evolution during reservoir depletion. We compare two natural gas fields with strong (San Juan coal basin) and weak (Barnett shale formation) sorption-mechanical coupling. The results of the study highlight the interplay between mechanical moduli, swelling isotherm parameters, and fracture compressibility in determining the impact of desorption on fracture permeability evolution during depletion.
Natural gas consumption currently constitutes a fifth of the total energy sources . About a half of nonassociated gas accrues to non-conventional gas reservoirs, mainly organic shales and coal seams . Non-conventional tight reservoirs have an extremely low permeability, a fair portion of which pertains to fractures as main fluid conduits. The openings of these fractures are dictated by lithology and the reservoir stresses, which may alter during reservoir development [2-5]. Two competitive geomechanical processes are known to affect stresses during depletion in organic-rich rocks: pressure drawdown and desorption-induced shrinkage. The latter is of significant importance in coals because sorbed gas constitutes more than 50% of total gas in place and desorption induces a substantial amount of rock shrinkage [6-8]. Sorbed gas in hydrocarbon-bearing shales constitutes 5-15% of the total gas in place. Sorption capacity is usually proportional to total organic carbon (TOC) in shales . Decreases in pore pressure associated with reservoir depletion cause increases in effective stresses, which often leads to fracture closure and a decrease in permeability. In contrast, desorption and matrix shrinkage result in a drop in effective stresses and an increase in permeability [8, 10, 11].
Over the years, the oil and gas industry has played a key role in the US energy sector. Oil companies have continually worked to develop technology to maximize performance and reduce the cost per barrel of crude produced, lately with the optimized performance of horizontal wells. Horizontal wells allow for more resources to be produced per well; however, they are more expensive since the horizontal section substantially increases length and drilling time. In drilling, now more than ever, optimization of the drilling parameters needs improvement to assist these companies in reducing the drilling time which can potentially save millions of dollars. Numerous individuals have analyzed theoretical rate of penetration (ROP) equations by finding the optimum value for constant drilling parameters for single bit runs, however, since the formation drilling variables change throughout the drilling process, so should the drilling controllable variables. Therefore, the idea of constant drilling parameters potentially results in wasted time and dollars for operators, which could be vastly improved through use of dynamic variables. This leads to a new research approach, one that attempts to optimize drilling parameters through the use of a swarm algorithm with the goal to reduce the drilling time through measurable improvement in rate of penetration, and therefore, reduced total drilling time. In the work presented herein a particle swarm optimization technique (PSO) has been incorporated to find the optimum combination of the drilling parameters, weight on bit (WOB) and revolutions per minute (RPM) for every foot of formation to be drilled. The integration of this new swarm algorithm into the optimization process allows for ROP equations to dynamically change, which can better adjust to the formation environmental variations throughout the drilling process. The results of this new area of research could change the way future horizontal wells are planned. Implementation of this algorithm can be applied in a multitude of ways; incorporating it as an artificial intelligence module in an existing drilling optimization simulator program, and/or directly integrated in the planning process by the drilling engineers to optimize drilling parameters for future planned wells.
Oil well drilling is a complex procedure and in order to optimize it, the physical phenomenon must be modeled as represented by the primary governing equation (Kerkar et al., 2014). Before the early 1980s, most oil wells were mainly drilled vertically (Helms, 2008). These vertical wells were influenced by many physical control variables including: weight on bit (WOB), revolutions per minute of the bit (RPM), drilling fluid type, drilling fluid viscosity, bit type, bit wear, etc. For drill bits, there are many sub segments of this area, however, most all of them can be classified into three categories: Natural Diamond Bits (NDB), Polycrystalline Diamond Compact Bits (PDC) and roller cone bits. NDB's are bits that have natural diamonds that are set along the surface of the bit face and grind the rock. PDC bits have polycrystalline diamond cutters set in the blades at the bit face and scrape or shear the rock. Roller cone bits are bits that have cones that roll along the rock face which crushes and gouges the rock as the bit teeth crush and penetrate into the rock. In this research, PDC bits will be incorporated since they are the most common.
Li, Wenda (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing) | Chen, Mian (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing) | Jin, Yan (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing) | Yang, Shuai (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing) | Zhang, Yayun (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing) | Chen, Yun (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing) | Tan, Peng (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijing)
Cement sheath is expected to provide mechanical zonal isolation and borehole integrity during well construction and well life. The damage of the cement sheath may result in abnormal annulus pressure and potential leakage. So internal wellbore pressure window based on cement failure is introduced to preserve zonal isolation during different well stages. A Two-dimensional analytical model using a multi-layer thick-wall cylinder is applied for calculating stress distribution in the casing-cement-formation system. In the model, we assumed perfect bonding (continuous stress and displacement) at the interfaces and plane-strain condition. Then the internal pressure limits can be obtained using the cement failure criteria for both axisymmetric and non-axisymmetric stress fields. Analytical solutions of the 2D model subjected to the axisymmetric stress field showed that the stress state, the mechanical properties of casing, cement sheath and formation, cased wellbore geometry and cement strength parameters both have effects on the internal pressure window, which provides guidance for the cement design. This method provides petroleum engineers a robust tool to maintain cement sheath integrity.
Cement sheath, as a part of well barriers, is expected to provide mechanical zonal isolation and borehole integrity during well construction and well life . The damage of the cement sheath may result in abnormal annulus pressure and potential leakage. Hence, the increasing awareness of avoiding the cement sheath failure has been raised among researchers. Thus internal wellbore pressure window based on the cement failure is introduced to control the wellbore pressure during different well stages for safety.
After cement sets, casing-cement-sheath system withstand the stresses induced by the well events and maintain integrity during the life of well . However, Cement sheath, casing and formation with different mechanical properties have different failure conditions. Many cases showed that abnormal annular pressure occurs without casing failure , which means that in some conditions the possibility of cement failure is higher than that of casing failure. So it is necessary to develop a model based on cement failure instead of casing failure, since cement failure happens prior to casing failure. On the other side, cement failure may destroy the wellbore integrity, creating flow channel for oil/gas migration between different formations. Excessive pressure and temperature change during well operations lead to significant damage to the cement sheath . Thus we need to develop a model to determine the internal wellbore pressure window maintaining cement sheath integrity (neglecting temperature variation) during different well stages.
Gil, I. (BP America) | Sebastian, H. (BP America) | Wendte, J. (BP America) | Lee, P. (BP America) | Patel, H. (BP America) | Cadwallader, S. (BP America) | Sun, T. (BP America) | Merletti, G. (BP America) | Fry, M. (BP America)
In shale reservoirs, adequate completion and fracture designs have proven critical to well performance. Changes in parameters such as number of clusters, cluster spacing, injection rate and injection volume have been shown to significantly affect both cluster efficiency and overall well productivity (Cadwallader et al., 2015). This study builds on previous work where multicluster cased & perforated completion designs were optimized using 3D frac and reservoir simulation (Sebastian et al., 2015).
This paper presents the results of an integrated completion optimization approach that combines the benefits and flexibility of using new completion hardware (coiled tubing activated sliding sleeves) and state-of-the-art 3D non-planar fracturing and reservoir modeling to optimize performance in a horizontal Eagle Ford Shale well. The overall goals of this work were to determine the production potential related to 100% cluster efficiency through single point injection, to optimize completion/frac design via changes in design parameters (sleeve spacing, injection rate, and injection volume), and to further validate modeling capability.
This document focuses on the fracture and reservoir modelling prediction and validation efforts to optimize execution of the trial. The results shown here were generated with a coupled 3D non-planar hydraulic fracturing simulator that uses the discrete element method to simulate the hydromechanical processes governing hydraulic fracturing propagation. Once the fracture geometry and associated conductivity were generated, they were exported to a 3D reservoir flow simulator, which in turn, generated curves for expected well productivity. Field surveillance data, including microseismic and production decline analysis, was used to validate the modeling predictions.
This paper builds on previous work targeted at improving cluster efficiency and well productivity in plugged and perforated shale completions in the Eagle Ford (Cadwallader et al., 2015). At the time, changes in completion design such as cluster distance, number of clusters, injection rate and injection volume were successfully used to increase cluster efficiency and overall well productivity. However, despite achieving positive results, surveillance data (including fiber optics) showed that, even after changes were implemented, cluster efficiency could undergo further improvement.