In this paper, we analyze and simulate the production data before and after an extended shut-in period from a horizontal well completed in the Montney Formation. After flowback and early post-flowback production, the well was shut-in for 7 months due to facility completion. When the well was reopened, the hydrocarbon production rates increased significantly compared to the values before the shut-in. To investigate the reasons behind this enhancement, we simulated three-phase production rates and bottom-hole pressure using the actual reservoir geological model. To match the production data before the shut-in period, we had to account for the reduction in oil and gas relative permeabilities due to water blockage. This was done by using multipliers of interblock fluid-flow transmissibility near the matrix-fracture interface. We used these transmissibility multipliers as matching parameters, to achieve the match between measured and simulated production data. However, the best history match was achieved, when the values of transmissibility multipliers are increased by 6.5 times after the shut-in. This suggests a significant increase in oil and gas relative permeabilities due to reduction in water blockage near fracture-matrix interface during the extended shut-in period. Since the simulation model was not able to capture the imbibition process controlled by different driving forces, we used transmissibility multipliers to mimic this phenomenon and its corresponding effects on production rates. In addition, we performed sensitivity analyses to investigate the effects of shut-in on the well productivity and economic profitability in terms of net present value (NPV). The results show that for this well, a 6-month shut-in period is optimal for maximizing NPV and hydrocarbon production.

Unconventional plays present a challenging case to design an optimized stimulation program and to maximize reservoir contact and hydrocarbon production. In this regard, conducting a reliable well spacing optimization study demands realistic and explicit fracture descriptions. This work applies an integrated technique to a multi-well case study in the Permian Basin to extract fracture dimensions based on microseismicity-derived behavioral fracture maps, while honoring the RTA-based estimates of the contributing fracture volume. The fracture dimensions are then used to conduct analytical and numerical studies to decide the optimal well spacing/placement design in the target formation. The numerical simulations in two stacked and staggered configurations confirm that although the staggered development causes a marginal decrease in the individual wells' performance, if successfully accomplished, it contributes to a higher vertical sweep efficiency from the section. Furthermore, comparing the approximations of failure planes, constructed based on the spatiotemporal analysis of microseismic events, with those achieved through seismic moment tensor inversion confirms that the collective behavior analysis gives fair estimates of fracture spatial evolutions.

To achieve economic production from shale gas reservoirs hydraulic fracturing is required. This stimulation technology facilitates the interconnection of the multiple pore systems with the wellbore. Particularly, shale gas reservoirs exhibit a dual porosity system linked to the free and adsorbed fluid phases, being the adsorbed phase a significant control on the long-term production. The adsorbed volume is strongly related to the total organic carbon (TOC) and thus, it is often assumed that higher hydrocarbons in place occur within the high TOC intervals. This study evaluates this relationship and the impact of the adsorbed phase to OGIP (original gas in place) and production behaviors. Analysis of petrophysical data and log-derived TOC of the Duvernay Formation reveals that variations in mineralogy impacts the quantity of TOC. It is observed that increase in carbonate contents correlate with lower organic contents, whereas increase in quartz and clays correlate with higher organic contents. Results of Langmuir isotherms indicate that methane adsorption capacity is directly proportional to the TOC content. Further, this study analyzes production data of two multi-fractured horizontal wells by analyzing the relative contribution of the adsorbed phase to the free gas. It is found that contribution of the adsorbed phase is maximum during the initial phase of the production cycle which declines as the reservoir pressure drops. The estimated relative contribution of the adsorbed phase to OGIP is nearly 50% which is significant to be considered negligible. Further, the contribution from the adsorbed phase is found to be 45% in the early phase of the production which drops down to 25% after 10 years of the production. Finally, this study illustrates that the relation of TOC with fluid characterization and recoverable reserves is complex and should be analyzed with the variation in adsorption and desorption capacity of lighter and heavier components.

Reducing fracture/well spacing and increasing hydraulic fracture stimulation treatment size are popular strategies for increasing hydrocarbon recovery from multi-fractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which not only can negatively impact the overall production, but also introduce complexities for production data analysis. To analyze the production data from two communicating wells, a semi-analytical model is developed and applied to a field case. The new semi-analytical model uses the dynamic drainage area (DDA) concept and assumes that the reservoir consists of two regions: a primary hydraulic fracture (PHF) and an adjacent enhanced fracture region (EFR) or non-stimulated region (NSR) in the reservoir. Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history matching framework to estimate the degree of communication between the wells by matching the production data. The model is first verified against more rigorous numerical simulation for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the reservoir simulation results and the new semi-analytical model. The semi-analytical model is then employed to history match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. First, only strong communication between pairs of wells (intra-pair communication) is considered. Then sink/source terms are added to account for intermediate degrees of communication between well pairs (inter-pair communication). Addition of the source/sink terms improves the history-matching quality of the three well pairs, while total material balance of the entire section is honored. A flexible, yet simple, semi-analytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.

Effective stimulation of infill (child) wells can be challenging: pressure sinks resulting from production of existing (parent) wells can impair child wells’ completions leading to a loss of production potential. Special completion techniques are required to better stimulate the new rock volume and divert the fracture energy away from the depleted zones. This study investigates pre-loading and re-fracking of parent wells as potential Pressure Sink Mitigation (PSM) techniques to minimize fracture asymmetry in child wells. The impact of these techniques on possible production uplift for both parent and child wells are also investigated. A black-oil reservoir flow simulation model was created and history matched to production from three existing parent wells in a Montney field. Three new child wells have been drilled in close proximity (100m-200m) to the parent wells and were subjected to fracture generation and subsequent production. The fracture generation of the child wells was directly modelled in the reservoir simulator with hydraulic fracture conductivity as an exponential function of pressure. The conductivity-pressure relationship of the newly created hydraulic fractures were validated quantitatively to field history data and qualitatively to a third-party fracture creation software. To limit the influence of the depleted zone, water was injected into the parent wells before the child well fractures are created. Since the child well fracture behavior is directly related to the pressure, a theoretical "reservoir pressure vs injected pre-load volume" relationship was generated. From the relationship, a series of simulation sensitivities were performed where the child well fracture creation and successive production were subjected to different pressure (pre-load) scenarios. The production uplift of each scenario over the non-preload base case was calculated to determine the efficacy of the technique and optimum injection volumes. Additionally, the time for the parent wells to return to their pre-child well production levels was quantified. A practical and robust simulation workflow to evaluate a pressure sink mitigation technique was successfully developed using an actual field case in the Montney formation. As infill drilling and high well density become standard operational practice, understanding how to limit the influence of existing depleted wells is essential for optimizing recovery from hydraulically fractured formations.

Analytical rate transient analysis (RTA) techniques are widely adopted for analyzing production data obtained from hydraulically fractured horizontal wells in tight or shale reservoirs. However, for a detailed characterization of the uncertain distributions of those complex heterogeneous and multi-scale fractures, numerical simulation and assisted history-matching approaches are often preferred. Generally, RTA results can be used to constrain the initial distributions of fracture properties (e.g., transmissivity, aperture, or intensity). A set of initial models are then perturbed during the assisted history-matching step. Unfortunately, the final updated models may deviate substantially from the initial RTA estimates; moreover, specific information regarding the flow regimes is not incorporated directly into the history-matching step. In this paper, a new assisted history-matching workflow is presented, where RTA results are used to constrain not only the initial DFN models, the interpreted flow regimes are also used to formulate a localization scheme for more efficient updating of the pertinent DFN model parameters. The outcome is an ensemble of DFN realizations that are calibrated to both geologic and dynamic production data. First, RTA interpretations and other pertinent geological data are used to infer the prior probability distributions of the unknown fracture parameters, from which an ensemble of initial DFN models is sampled. Next, the DFN models are subjected to numerical multiphase flow simulation; the predicted production profiles are compared with the actual historical production data. Finally, the fracture parameters are adjusted following an indicator-based probability perturbation method, which is capable of minimizing the objective function and reducing the uncertainties in the unknown fracture parameters simultaneously. A key feature is that the flow regimes identified from RTA are used to formulate a localization strategy, where individual segments of the production data is used to tune only a specified subset of the unknown model parameters. The adoption of localization strategies in other settings has been demonstrated to improve the convergence behavior of such ill-posed inverse problems. In a case study, the method is applied to characterize the probability distributions of four parameters in a multifractured shale gas well: primary fracture transmissivity, aperture of the secondary fracture, transmissivity of the secondary induced fracture and global fracture intensity. Results of the sensitivity analysis reveal that the production performance is most sensitive to these particular parameters. Their probability distributions are updated following the proposed approach to match the production history. Multiple realizations of the DFN model are sampled. A probabilistic approach facilitates the representation of uncertainties in fracture parameters via multiple equally-probable DFN models and their corresponding upscaled flow-simulation models. A more comprehensive and robust approach is presented for integrating specific RTA interpretations and estimations into various steps of the history-matching process.

The purpose of this paper is to quantify the importance of lateral heterogeneity of permeability and porosity when modeling horizontal, multi-fractured tight unconventional wells exhibiting layer-wise fluid heterogeneity. Fluid and petrophysical properties are taken from the Eagle Ford basin. A numerical simulation model of a horizontal well drainage volume with multiple planar fractures is created for two layers having distinct fluids (e.g. solution GORs). The model is populated with laterally-heterogeneous, correlated porosities and permeabilities (k=aφ b ) ranging from 4 to 14 %, and 59 to 2600 nd, respectively. The layer petrophysical properties can map differently for each layer, but the arithmetic average properties are equal for each layer. For all cases studied we assume the initial solution GOR to be areally homogeneous in a given layer; the solution GORs considered range from 1000 to 8000 scf/STB. The petrophysical heterogeneous cases are compared with homogeneous cases (no lateral property variation), both models with the same average petrophysical properties. Results show that for a heterogeneous-petrophysical case with varying lateral contrast between the petrophysical properties in the two layers, individual fractures produce with distinct GORs, even showing a variation of producing GOR (R p ) from different locations within a single hydraulic fracture. However, the total, well-producing GOR behavior is very similar for the heterogeneous- and homogeneous-petrophysical cases, regardless of the fluid contrast in the two layers, when the maximum-to-minimum permeability ratio k max /k min <10. These observations apply when flowing bottomhole pressure (BHP) is above (single-phase) or below (two-phase) in-situ saturation pressure. These results indicate that lateral petrophysical heterogeneity can often be ignored when modeling tight unconventional wells. The explanation for this non-intuitive result is that the producing surface area from many hydraulic fractures is so extensive that the well-average GOR is very close to the GOR of a well producing from two petrophysically-homogeneous layers having arithmetic-average porosity and permeability. This finding reduces considerably the simulation run time (CPU) using a single "average" hydraulic fracture element, where the key fluid heterogeneity is solution GOR in each layer. Another important finding is that significant time-variation of producing well GOR may result even when flowing BHP remains higher than in-situ saturation pressures (i.e. single-phase flow). This behavior is caused by differential depletion of the individual layers with fluid contrast in viscosity and compressibility, i.e. without any contrast in layer permeabilities.

Well spacing and completion optimization in tight and shale reservoirs is a multi-dimensional task which comprise reservoir rock and fluid characterization, well performance study, inter-well communication analysis, and economic evaluation. Two sources of pressure data for characterization of inter-well communication include offset well pressure monitoring during hydraulic fracturing and controlled communication (interference) tests through staggered production. Both types of inter-well communication tests have become common among the operators in tight and shale reservoirs. However, quantitative analysis tools for interpretation of the test results are in their infancy. The focus of this study is quantitative analysis of pressure interference tests. In this study, an analytical model is developed for quantitative analysis of communication between multi-fractured horizontal wells (MFHWs) using pressure data from production and monitoring well pairs. The governing partial differential equation for the more general case of coupled flow in hydraulic fracture and matrix systems is solved using the Laplace transform. In order to validate the analytical model, the results from the analytical solution are compared against numerical simulation models. The analytical model of this study is applied to two field case from Montney formation. In these cases, a well from a multi-well pad is put on production and bottom-hole pressure of a monitoring well from the same pad is recorded using down-hole recorders. Communications between the wells is quantified using the analytical models of this study. The model of this study serves as a novel and practical tool for quantitative analysis and interpretation of inter-well communication in MFHWs. Integration of the model with other direct diagnostic and measurement tools can provide insight into optimized completion intensity for MFHWs.

Recently it has been demonstrated that rate-transient analysis (RTA) performed on flowback data frommulti-fractured horizontal wells (MFHWs) can provide timely estimates of hydraulic fracture properties. This information can be used to inform stimulation treatment design on upcoming wells as well as other important operational and development decisions. However, RTA of flowback data may be complicated by rapidly changing operating conditions, dynamic hydraulic fracture properties and multi-phase flow in the fractures, complex fracture geometry, and variable fracture and reservoir properties along the MFHW, among other factors. While some constraints on RTA model assumptions may be applied through a carefully-designed surveillance and testing program in the field (e.g. to constrain fracture geometry), still others require laboratory measurements. In this work, an integrated flowback RTA workflow, designed to reduce uncertainty in derived hydraulic fracture properties, is demonstrated using flowback data from MFHWs producing black oil from low-permeability reservoirs in the Montney and Duvernay formations. The workflow includes rigorous flow-regime identification used for RTA model selection, straight-line analysis (SLA) to provide initial estimates of hydraulic fracture properties, and model history matching of flowback data to refine hydraulic fracture property estimates. The model history matching is performed using a recently-introduced semi-analytical, dual-porosity, dynamic drainage area (DP-DDA) model that incorporates primary (propped) hydraulic fractures (PHF) as well as a dual-porosity enhanced fracture region (EFR) with an unpropped (secondary) fracture network. Inclusion of both the PHF and EFR components addresses the need to incorporate both propped and unpropped fractures and fracture complexity in the modeling. The DP-DDA model is constrained using estimates of propped fracture conductivity and unpropped fracture permeability (measured as a function of stress), and unpropped fracture compressibility values, obtained in the laboratory for Montney and Duvernay core samples. Use of these critical laboratory data serves to improve the confidencein the modeling results. The case studies provided herein demonstrate a rigorous workflow for obtaining more confident hydraulic fracture property estimates from flowback data through the application of RTA techniques constrained by both field and laboratory data.

An experimental procedure was developed to incorporate the mechanisms of Gas-Cycling Enhanced Oil Recovery (GCEOR) phase behavior, IFT change, swelling, viscosity reduction and residual-liquid shrinkage in the presence of porous media possessing propped hydraulic fractures and matrix. Relatively large hydrocarbon pore volumes are possible using this technique whereby effluent compositions, densities and volumes are measured. The importance of rock and fluid properties is investigated along with operating pressure, injection gas composition and levels of primary depletion. Experimental oil flux is measured and scaled to forecast field production rates based on field frac data. The experimental design for core-flow testing has provided insight into GCEOR. Two dominant flow regimes are incorporated: matrix mass transfer into and from the fracture(s) and flow within the fracture(s). Reservoirs tested exhibited pressures from 3000 to over 5000 psi and temperatures from 140 to 220 F. Huff pressures were as high as 6000 psi. Over fortyseven separate primary depletions were accomplished followed by Huff and Puff (HnP) GCEOR on multiple rock and fluid types. Design parameters were changed from run to run allowing for insight into GCEOR operation and design. Simulation of experimental results with subsequent scale-up for field forecasting was performed. From the many primary depletion tests followed by GCEOR, using a variety of injection gases and reservoir fluids the effects of cycling pressure, injection gas composition, soak time, level of primary depletion before GCEOR, and other parameters were investigated. Measured results indicate that recovery of OOIP can be more than doubled compared to primary production, in some cases, by implementing GCEOR. From the broad, accumulated data base, the following have been observed: Cycling pressure should be optimized (highest pressure does not necessarily perform the best). Gas quality can, in some cases, play a major role but should be considered and quantified in GCEOR applications. oak time/Huff time in many cases may be optimized to maximize production cycles and minimize injection cycles. Gas utilization values, for well-designed GCEOR systems, are low compared to conventional continuous gas injection projects causing Huff and Puff GCEOR to approach gas storage performance. Gas utilization appears to be sensitive to the mechanisms at work in GCEOR. Less depletion before GCEOR initiation can accelerate recovery and can, in some cases, access residual oil that was not produced at higher levels of primary depletion. Contrary to expectation, the rock character may dominate GCEOR performance. In a subset of this testing, the rock heterogeneity had a more dominant role than fluid properties including miscibility. Simulation can be an important tool to upscale the experimental measurements to field design. It is shown that simulation tuned to measured, experimental Primary Depletion and GCEOR performance including phase behavior and rock-fluid interaction, provides more optimistic forecasts of field GCEOR performance than a simulator based on field-scale Primary Depletion data alone.

With increased drilling activity associated with development of unconventional reservoirs, many operators are reporting both stimulation and production interference between wells. Interference between existing production wells (parent wells) and newly completed infill wells (child wells) is often associated with production impairment ( Marongiu-Porcu et al. 2015 ; Ajisafe et al. 2017 ; Defeu et al. 2018 and Manchanda et al. 2018 a). The objective of this work is to develop guidelines concerning infill wells completion scheme to minimize parent-child wells interference in a typical pad, with infill drilling in the Duvernay formation. The area of interest selected within the Duvernay formation consists of three parent wells and two child wells. An integrated mechanical earth model (MEM) was constructed for the area using public databases. The created 3D-geological model included petrophysical and geomechanical properties along with a 2D discrete natural-fracture network representing the distribution of natural fractures in the reservoir. Hydraulic fractures in parent wells were modeled using original stress settings from the 3D-MEM. Then, a dynamic model was constructed for the three parent wells and production simulation was run for five years. Pressure distribution at the time when child wells came into production was extracted and 3D depleted stress distribution was computed using a finite element method that included the effect of pore pressure decrease and principal stress magnitude and orientation changes. Then, hydraulic fracture modeling was performed for the two child wells using the new depleted stress distribution, and finally a five-well dynamic model was created. Sensitivity analyses were performed on the hydraulic fracture parameters of the child wells with the objective of maximizing recovery by accessing more virgin reservoir area between the parent wells. Hydraulic fracture modeling followed by dynamic simulation was done in the pad for multiple cases. Fracture geometry, hydraulic/propped surface area, and fracture conductivity in child wells were extracted and analyzed against production performance of the wells. This study shows a holistic approach in modeling the impact of completion modifications on the child wells performance in an infill drilling scenario. A 3D-geomechanical model coupled with reservoir simulation allowed simulating the propagation of hydraulic fractures in the presence of pressure depleted regions. Results confirmed that the main reason for under-performance of child wells in Duvernay is the stress change induced by the reservoir pressure depletion associated with the parent wells production hence, influencing the child wells hydraulic fractures propagation patterns.

Some simulation studies of unconventional wells with a declining flowing pressure show a significant increase (hump) in the oil rate at the time when the flowing pressure crosses the bubble point. This unexpected "oil-rate hump" is subsequently followed by the traditionally expected rate decline. The unexplained rate hump raises various questions: The first question is: is it real or simply an artifact of the mathematics of numerical simulation? And if real, other question arise, including: how do reserve estimation methods that are based on rate decline apply to an increase? Or, does a rate increase mean one should produce the wells at pressures below the bubble point pressure to accelerate production of the oil associated with the rate hump? The main objective of this paper is to investigate whether a rate hump is a result of numerical errors of simulators especially as grid-blocks drop below bubblepoint pressure, or if it is an intrinsic response of formulations of two - phase flow under some conditions of flowing pressure, etc. And if the latter, what are the conditions that lead to a rate hump. We start with the partial differential equations of two-phase (gas and oil) flow for transient linear flow and re-write them in a form similar to those of single-phase flow. This allows term-to-term comparison of the two-phase formulation with the corresponding single-phase one. Through this comparison and the analytical and numerical solutions presented, we suggest that the rate increase is not because of numerical errors, instead it is related to at least three groups of parameters(i) fluid properties impacting the ratio between single-phase and two-phase compressibility. (ii) flow parameters that reflect how efficiently the evolved solution gas displaces the oil, and (iii) the rate at which the pressure at the wellbore is declining. Furthermore, a series of numerical simulations are conducted to:(i) investigate the effect of parameters of significance and (ii) extend the range of investigation to more practical cases such as those more common to completion in unconventional reservoirs. When we choose typical values for reservoir and fluid properties, and operating conditions from unconventional basins we observe significant rate increases that last for many months and could make a significant contribution to early production. Next, we look for evidence of the "rate hump" in actual field data. Our review of field data did not result in any convincing data sets with clearly defined rate humps. While a more exhaustive review of field data may reveal this phenomenon to be real, we discuss conditions that may mask or negate the rate hump. We also provide preliminary guidelines for input parameters so that the simulation model does not exhibit the rate hump. To the best of our knowledge, this is the first time that the rate hump is being investigated in the literature.

Aimed at sharing the unconventional wisdom gained from a hydraulic fracturing monitoring case study in the Montney tight gas play, the work showcases the ability of 4D modeling of collective behaviors of microseismic events to chase the frac fluid and navigate the spatiotemporal fracture evolution. Moreover, microseismicity-derived deformation fields are integrated with volumetric estimates made by rate transient analysis to calibrate spatially-constrained SRV models. Through the case study, we give evidence of fracture containment, evaluate the role of natural fractures and the use of diverting agents, estimate cluster efficiencies, conduct analytical well spacing optimization, model productivity decline induced by communication frac-hits from offsets, and provide contributing fracture dimensions and numerical production forecasts. To support the interpretations, we supplement the work by the results of 3D physics-based analytical modeling and multi-phase numerical simulations, and the findings are then validated using two extensive datasets: production profiles acquired by fiber optic DAS, and reservoir fluid fingerprints extracted from mud logs. Besides describing the evolution of seismicity during the treatment, the applied integrated fracture mapping process gives a more reliable and unique SRV structure that streamlines forward modeling and simulations in unconventional reservoirs as well as contributes to solving inverse problems more mechanistically.

Cyclic gas injection in hydraulically-fractured wells has been successfully applied as an enhanced oil recovery (EOR) method in tight unconventional basins such as the Permian and Eagle Ford. However, displacement processes (continuous gas, solvent or water injection) such as those piloted in the relatively more permeable Bakken formation have not been considered in tighter basins. In this work, we present a novel displacement process that uses alternating injecting and producing hydraulic fractures to flood the inter-fracture region around a horizontal well. We demonstrate that the method is feasible as long as suitable fracture geometries can be generated. A reservoir geomodel of a typical Montney gas condensate reservoir was constructed using publicly available data. Rock mechanics parameters were integrated into the model alongside completion and pumping schedule information to predict hydraulic fracture propagation and geometries representative of the typical stimulated volumes in Montney. A compositional numerical reservoir simulator was then used to test the proposed EOR process in a gas condensate reservoir where we forecast liquid recovery under different frac-to-frac continuous gas injection flooding scenarios. Sensitivities to study the effect of fracture spacing and complexity, solvent composition, starting time of gas injection, and matrix permeability were performed. With simultaneous injection and production from alternating hydraulic fractures, it is possible to flood the volumes between them and consequently avoid the drawbacks of huff ’n’ puff processes. By using a more rigorous fracture description, we can reproduce the interactions between fractures and determine how they affect the conformance of the displacement front. Modeling results showed that frac-to-frac displacement process can significantly improve the condensate recovery compared to primary or even huff n puff EOR process. They also showed that the frac-to-frac EOR process is feasible only if the formation mechanical properties and in-situ stresses are such that the resulting hydraulic fractures exhibit aligned planar geometries. If high-intensity natural fracture networks are present, the hydraulic fractures tend to form complex geometries that negatively affect the conformance of the flooding front. The study also showed that there is an optimal spacing between the injecting and producing fractures that would allow for the efficient utilization of the EOR agent; this spacing was shown to have a strong dependence on matrix permeability. Composition of injected solvent and starting time of gas injection doesn’t seem to have considerable impact on incremental recovery due to frac-to-frac displacement.

Black oil tables used in reservoir simulation and/or RTA/PTA history matching exercises are generated based on a fixed surface process (number of separator stages, psep, Tsep). However, even though the number of separator stages remain fixed, the separator pressure and temperature vary over time. This variation of separator conditions over time leads to an inconsistency between the rates used in history matching (assumes constant separator conditions) and the actual measured rates (changing separator conditions in the field). This paper provides a method to adjust all measured rates to a fixed surface process to ensure consistency between the black oil tables and rates used in history matching, and it also investigates for what fluid systems this normalization procedure is important. First, daily wellstream compositions are predicted based on a common equation of state (EOS) model, welltest and production data (separator oil and gas compositions, GOR, stock tank liquid API). Thereafter, these wellstreams are run through a fixed surface process, with the same separator pressure and temperature used to generate the black oil tables utilized in the reservoir modeling. Several practical observations are made. CGR normalization is in general not important for black- and volatile oil systems. However, it may be very important for near-critical fluids and gas condensate systems.The obvious application of the proposed normalization scheme is to calculate a set of consistent oil and gas rates for every well that can be used for history-matching purposes. Additionally, as black oil PVT properties are a function of the separator process, it is recommended to define a common surface process for an entire field or basin to ensure consistent apple-to-apple comparison between wells. Technical contributions include a qualitative framework of when CGR normalization is important and when it is not. The paper also proposes a simple solution to a widely known, but under-addressed and overlooked problem, not earlier presented in the open literature.

A straightforward test with debatable analysis methods, the diagnostic fracture injection test (DFIT) is a pressure-transient test extensively used for reservoir and geomechanical characterization of tight/shale formations. The test provides some key data and information to reservoir and well completion engineers including instantaneous shut-in pressure (ISIP), pore pressure, closure stress, fluid efficiency, reservoir flow capacity, and fracture leak-off regime. A comprehensive regional or field-wide study of the DFITs is deemed very useful for operators at any stage of exploration and development. In this study, DFITs from a group of 174 Montney and Duvernay wells operated by more than 30 producing companies are quality checked and analyzed consistently. The results from DFITs are then compared against the standard poroelasticity equation. The data set of the current study covers a wide range of DFIT conditions and reservoir and geomechanical properties which helps the authors develop reliable correlations for reservoir characterization purposes. True vertical depth (TVD) of the wells ranges from less than 1000m to more than 4000m leading to a wide range of pressure and stress conditions. The study also covers all the geographical areas of Montney and Duvernay. The results ofthe DFITs are used to develop usefulcross-plot betweenpore pressure and closure pressure.A relationship between closure pressure from compliance method and G-function analysis method for Montney and Duvernay is also provided. Results of example DFITs from depleted areas were also provided which gives an idea about the depletion level and the associated well performance degradation. The current study gives field-wide understanding of the variations and distributions of reservoir and geomechanical properties in Montney and Duvernay based on DFIT analysis of a sizable population of wells.

A new stage-by-stage analytical framework to identify and control high water influx stages in horizontal wells was successfully used in a multi-layer reservoir in Southeast Saskatchewan, Canada. The wells of interest were drilled in the Midale formation and hydraulically fractured through coil with cemented liners using a borate cross-linked guar gellant. The objective of the project was to develop a robust method to aggregate and analyze multidisciplinary data to identify stages with prolific water inflow and employ multi-cycle closeable sleeves to isolate them. When the correct data is available this framework can be applied at the time of completion to improve well economics through reduced lifting and disposal costs. A multivariate approach is necessary to begin to understand flow per stage in the absence of production logging. This framework involves collecting all available data: geological, geophysical, raw data-van feeds, pressure signatures, frac fluid viscosity profiles, break times, production and tracer concentrations to build a model for targeting sleeve closures. Data collected through on-site laboratories during the hydraulic fracturing treatment allow early identification of stages for further analysis. Stages where full breaking of frac fluids under reservoir conditions is not observed are identified as candidates for possible intervention. High frac fluid viscosities have the potential to increase fracture height growth and connect the wellbore to layers that have mobile water, depending on fracture height growth limiting mechanisms (Fisher, M. K. et al 2012). Particulate water tracers allow for water inflow to be uniquely attributed to individual stages, where higher concentrations are associated with higher inflow. Combined with pressure signatures and initial swabbing data, this technique can allow the operator to better optimize the well from day one. Production analysis before and after closing sleeves serves as the ultimate score-card for this framework. Mitigation of unwanted water influx was achieved using this framework to shut in certain stages early in the well's life. On-site quality control, detailed data collection during hydraulic fracturing, tracer concentrations and initial swabbing provided the necessary signals. Closeable sleeves permitted the fractures to heal immediately after the completion, but also allowed for the optionality to mitigate high water inflow if it was identified. This paper details the results from a well, where the water production decreased by approximately 30% while the oil rate increased. This framework allows for real-time data driven decision making. This enables significant efficiency gains in completion and intervention costs, equipment sizing, facility infrastructure, and lifting costs. This is accomplished through combining multiple datasets, including detailed on-site and after-the-fact frac analysis and solid particulate water tracers to leverage closeable sleeve technology. Potential areas for further applications of this framework include infill drilling in legacy waterfloods or when drilling wells in close vertical proximity to aquifers. This framework is most applicable when attempting to optimize fracture designs when working in new areas and new reservoirs.

Natural fractures, fissures, and microfractures are well-known contributors to production performance of shale reservoirs. Complex fracture geometries can be generated by either small-scale fracturing, DFIT, or large volume fracture stimulation, because the activation of pre-existing natural fractures, fissures, and microfractures plays a significant role on generation of induced hydraulic fractures. Therefore, much more attention should be paid to the model development of DFIT complexity. In previous work, Chen et al. (2017a) built a complex fracture-network model for after-closure analysis of DIFT by considering natural fractures. Based on that, this paper introduces a generalized model with random fracture geometry caused by natural fractures, fissures, and microfractures. First, the model flexibility is demonstrated by different complex fracture cases, namely opening-fissure fracture network, tree-like fracture network, radial multiple fracture network, and mutually orthogonal fracture network. It is found that the pressure derivative reaches constant level, no matter what the fracture geometry is. Furthermore, the reservoir permeability of field examples from actual DFIT tests in Marcellus shale reservoir is quantified using the log-log diagnostic plots based on the model solutions. Finally, the Nolte G-function is applied to verify the estimated results. We find that the results from the two methods are consistent. This work primarily focuses on quantifying the reservoir permeability, while in the future more efforts will be made to identify the fracture properties using the proposed model.

In this Paper, the methods developed by Clarkson et al. (2014) are used to analyze flowback data, which involves modeling flow both before and after the breakthrough of formation fluids. Despite the versatility of these techniques, achieving an optimal combination of parameters is often difficult with a single deterministic analysis. Because of the uncertainty in key model parameters, this problem is an ideal candidate for uncertainty quantification and advanced assisted history-matching techniques, including Monte Carlo (MC) simulation and genetic algorithms (GAs) amongst others. MC simulation, for example, can be used for both the purpose of assisted history-matching and uncertainty quantification of key fracture parameters. In this work, several techniques are tested including both single-objective (SO) and multi-objective (MO) algorithms for history-matching and uncertainty quantification, using a light tight oil (LTO) field case. The results of this analysis suggest that many different algorithms can be used to achieve similar optimization results, making these viable methods for developing an optimal set of key uncertain fracture parameters. An indication of uncertainty can also be achieved, which assists in understanding the range of parameters which can be used to successfully match the flowback data.

Productivity of hydraulically stimulated unconventional wells depends greatly on the successful interconnection of the enhanced permeability and the natural fracture system. Such success is achived by proper understanding of the distribution of mechanical properties of the rock, presence of natural fractures, and regional stresses characterisitcs. With this understanding of the reservoirthe response of the rock to the stimulation can be quantified. Currrently, there are multiples approaches adopted by the industry to support such a process, making fracture designs more robust and reliable. However, theseworkflows often neglect the underlying physics of pressure wave propagation throughout the reservoir, crossing geological features such as faults, natural fractures, ash and karst layers among others. Pressure depletion caused by production of the first well in a section (parent well) generates continuous changes in stress magnitude and orientation. Simplistic geomechanical models ignore such effects and usually are built based on original conditions, resulting in overestimation of induced strain which will be reflected in oversized hydraulic fracture jobs that negatively affect not only the subsequent wells (child wells) but also the first well in section itself. Negative effects such as frac hits are usually irreversible, and proper estimation of the potential damage needs to be quantified and understood in order to put in place a mitigation plan. This work presents a workflow where changes in the pressure field are incorporated and taken into consideration during geomechanical modeling of induced strain using full continuum mechanics. As a result, hydraulic fracture designs are adjusted to the reservoir conditions at the time a new child well will be drilled and completed, thus reducing thepotential for negative effects such as frac hits. A fracture design for a planned child well to be drilled after two years of production of its parentis presented under two scenarios: first, ascenario ignoring the effect of pressure depletion, second, a scenario using the full continuum geomechanical solution to account for the effects of parent depletion. Results of the fracture design are migrated to dynamic simulation to estimate the effect on the resulting EUR.