bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Studies of Integrated Flowback Analysis: Examples from the Montney and Duvernay Formations
Authors: Clarkson Christopher R. , Williams-Kovacs Jesse , Zhang Zhenzihao , Yuan Bin , Ghanizadeh Amin , Hamdi Hamidreza , Islam Arshad 
Published: March 2020

Abstract
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.
Pressure Sink Mitigation: Effect of Preloading Parent Wells to Better Control Infill Hydraulic Fracture Propagation
Authors: Joslin Kevin , Ranjbar Ehsan , Shahamat Sadeq , Somanchi Kiran 
Published: March 2020

Abstract
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.
An Alternative Technique for Fast Permeability Measurements of Gas Shales
Authors: Feng Ruimin , Chen Shengnan , Pang Yu 
Published: March 2020

Abstract
Laboratory pulse-decay techniques are effective for determining rock permeabilities ranging from 0.01 μd to 0.1 md. However, the measurement time is fairly long, reaching up to several hours to days when testing gas shales because their permeability can be as low as dozens of nano-Darcys. This paper proposes an alternative pulse-decay technique that offers accurate permeability measurements within a considerably short time frame.
A radial-flow pulse decay method with a new experimental design is developed, which employs two gas reservoirs of the same volume and two pressure pulses with the same magnitude, one "positive" and one "negative". A mathematical model is then developed to numerically verify the feasibility of the newly developed technique and analytically solved for permeability estimation. Pressure responses with time in the radial direction of the test sample are analyzed and compared with those in the axial direction by solving the mathematical model. A concentric circular cavity with a diameter of 0.51 cm is created along the core samples, which are tested to experimentally demonstrate the applicability of the technique.
The numerical results showed that the pressure pulse of the radial flow decays much faster than the axial flow and at least a 10-fold reduction in measurement time can be achieved. Numerical results indicated that the proposed technique is capable of eliminating the effects of the compressive storage and gas sorption in the permeability measurement; while great efforts need to be put to correct such effects when employing conventional transient techniques. An in-depth comparison is experimentally made between the proposed method and the conventional axial-flow method. The experimental results presented in the study confirm that fast and accurate measurements can be achieved using the proposed technique.
Analysis of Communicating Multi-Fractured Horizontal Well Production Data Using the Dynamic Drainage Area Concept
Authors: Ahmadi Hossein , Clarkson Christopher R. , Hamdi Hamidreza , Behmanesh Hamid 
Published: March 2020

Abstract
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.
Field-Wide Review of Diagnostic Fracture Injection Tests DFIT in Montney and Duvernay Formations – Part 1: Stress and Pressure Distributions
Authors: Haghshenas Behjat , Qanbari Farhad 
Published: March 2020

Abstract
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.
Investigation of Cyclic Gas Injection in the Gas Condensate Window of Unconventional Reservoirs
Authors: Santiago Carla Jordana , Kantzas Apostolos 
Published: March 2020

Abstract
Reservoirs such as Duvernay, Montney and Eagle Ford are segmented in different areas, ranging from predominantly dry gas regions, to wet gas and oil regions. Extensive research has focused on the application of enhanced recovery methods in the oil window of such reservoirs. In this paper, we discuss the application of enhanced recovery in the gas condensate window, with the objective to investigate the impact of diffusion on liquid dropout and vaporization on a matrix level.
The Maxwell-Stefan equations were used to account for diffusion phenomena in the medium, and a phase behavior routine was implemented including nano-confinement effects. Numerical experiments were performed to evaluate the range of variability of recovery factors in a cyclic gas injection scenario. Methane was used as injection gas, and 1, 2 and 4 cyclic injection stages were modelled at the scale of a matrix block. Sensitivity was performed using a leaner and a richer gas composition, as well as two levels of permeability (50 and 100 nD). This allowed detailed investigation of time and location of occurrence of liquid dropout through saturation profile maps.
Due to molecular partitioning, the phase envelope shifts as production proceeds, generating an accumulation of heavier hydrocarbons in the medium. Since injectivity is reduced in lower permeability media, injection pressure ramp up needs to be controlled to prevent condensate blockage. As a result, longer cycles are needed in the lower permeability case to achieve equivalent recovery.
Liquid dropout is recurrent during production after each injection cycle, however, increasing the number of stages resulted in overall lower liquid saturation during subsequent production. Additionally, saturation profile maps indicate that the locus of condensate banks varies between each stage. As more injection stages are performed, a leaner gas remains in the vicinity of the fracture boundary and the condensate bank is formed further into the matrix block.
Although more cycles improved recovery of heavier hydrocarbons, faster cycles resulted in lesser penetration of the injection gas into the porous medium. This behavior is more accentuated in the lower permeability cases. Nevertheless, recovery of heavier fractions is still higher compared to the primary production base case. Sensitivity studies will dictate the optimum number of stages for a fixed timeframe.
In this work we use a combination of physics involved in flow in tight reservoirs to demonstrate how saturation profile maps can be used as a tool to improve enhanced recovery strategy.
An Automated Physics-Based Workflow for Identification and Classification of Drilling Dysfunctions Drives Drilling Efficiency and Transparency for Completion Design
Authors: Saini Gurtej Singh , Hender Donald , James Chris , Sankaran Sathish , Sen Vikram , van Oort Eric 
Published: March 2020

Abstract
In this paper, a new workflow for data wrangling, cleansing, processing, automated identification and classification of drilling dysfunctions (e.g. bit balling, drillstring vibrations, etc.) for any number of wells is presented. Statistically-derived baseline rock strengths were used to improve drilling efficiency and transparency in completions design. The methodology leverages commonly available rig surface sensor data and mud motor parameters. Data handling and processing across multiple databases was automated. Time-series data was converted to depth-based data, and drilling dysfunction indicator metrics (mechanical specific energy - MSE, depth-of-cut, etc.) were computed. Subsequently, the combined data set was segmented based on formation tops, bottom hole assembly (BHA) used, and hole sections. A multivariate physics-based decision tree methodology was then applied for identification and classification of drilling dysfunction. A baseline MSE was statistically derived and a subsurface rock strength database was created for every formation in every well within a given prospect.
Over 100 historical unconventional wells across two shale basins were analyzed using the new workflow, and 10 different dysfunction categories were classified. The most commonly encountered drilling dysfunctions were whirl, stick-slip, and bit balling. An algorithm generates a set of reports per well based on independent segments for individual drilling operations, including strip charts of drilling parameters and dysfunction indicators, with identification of potential (low/high) problem areas. Auto-generated scatter plots, identifying optimal control parameters for every geological formation at a given location, are used for planning future wells and improving drilling performance. The calculated MSE baselines were averaged to build a repository of baseline MSEs per formation, which in turn can be utilized as a diagnostic tool for real-time MSE surveillance. The MSE baseline information can also be used as a representation of unconfined compressive strength (UCS), and thus used to formulate a reliable rock hardness map to enhance completion design.
Manual dysfunction analysis is time- and labor-intensive, and therefore often done either incompletely or bypassed altogether. Automating this process reduces time and effort significantly. The novelty of this work lies in the translation of the qualitative understanding of MSE to a reliable quantification of rock strength through the analysis of magnitudes and trends in drilling parameters and dysfunction indicators. Screening out drilling dysfunctions enables a much better rock strength approximation to aid completion optimization.
Permeability of Tight Sand and Shale Formations: A Dual Mechanism Approach for Micro and Nanodarcy Reservoirs
Authors: Ziarani Ali S. , Aguilera Roberto , Cui Albert X. 
Published: March 2020

Abstract
Traditionally, viscous flow based on Darcy's law has been considered as the primary transport mechanism in petroleum reservoirs. In the micropores of tight sands and nanopores of shale, fluid transport is more complicated than Darcy flow. In unconventional gas reservoirs, in addition to viscous flow, diffusion can play a significant role in gas transport especially in ultra-low permeability reservoirs.
An easy-to-use dual mechanism approach that accounts for the contribution of both Darcy flow and diffusion to apparent permeability in tight sandstone and shale formations is developed in this paper. The study elaborates on how the traditional Darcy permeability is modified to account for the effect of diffusion. This is achieved through an additional term that accounts for diffusion contribution as a function of gas viscosity, compressibility, and diffusion coefficient. The proposed model is then applied to experimental data of tight gas and shale gas reservoirs.
For the case of tight gas reservoirs, Mesaverde sandstone data from the United States Basins are analyzed. For the shale gas case, Duvernay formation in the Western Canada Sedimentary Basin is studied. Laboratory measured permeability supplemented with petrographical SEM images and MICP data is investigated. The application of the proposed methodology is demonstrated for estimating the percentage of diffusion contribution to total gas transport in the rock matrix.
The transition from viscous flow to diffusion is identified with the use of Knudsen number. Viscous flow is usually observed in larger pores and higher pressures where continuous flow is driven by a pressure gradient. In micropores, and especially nanopores of shale formations, diffusion driven by a concentration gradient becomes the major transport mechanism.
The results indicate that in extremely tight reservoirs with nanodarcy permeability, diffusion is the dominant transport mechanism for gas delivery from matrix nanopores to natural fractures. This is important and should not be ignored in engineering applications. Practical guidelines and recommendations are provided for the proper use of the proposed methodology.
A Systematic Study of Water-Rock Reactions to Reveal the Relationship Between Total Dissolved Solids and Colloidal System Parameters
Authors: Zhang Lifu , Hascakir Berna 
Published: March 2020

Abstract
Understanding water-rock interactions occurring during hydraulic fracturing is vital to better engineer the hydraulic fracturing water. In this study, a systematic model of water-rock reactions is presented to mimic the interaction of reservoir rock with water.
To investigate the water-rock interaction Marcellus Formation was selected. The reservoir rock samples from the Marcellus Formation were first characterized for its mineral composition by an X-ray diffraction (XRD) and for its elemental composition by an X-Ray fluorescence (XRF). Based on XRD results 3 major minerals were found in Marcellus shale; quartz, calcite, and illite. Later, these minerals with high purity content were ordered from an external chemical company to prepare pseudo rock samples and single-, two-, and three- component mineral-deionized water systems were prepared. The supernatant of these solutions were analyzed for their pH, total dissolved solids (TDS) content, particle size of the colloidal system, and zeta potential of the colloidal systems.
For single-component mineral-water systems, it has been observed that pH and TDS in general give a linear relation with the mineral concentration. For two component mineral-water systems, these relations got weaker and for the three-component systems, only TDS gives good linear relation to the mineral concentration at room temperature. When the experiments repeated at 75 °C to see the effect of temperature on dissolution of minerals in a single-component system, no difference was observed in the linear relations, however, it has been observed that particle sizes of the colloidal systems for all single-component mineral-water system correlates with the TDS content of the water. It should be noted that while particle sizes measure in water gives an idea of the average size of the suspended particles in water, TDS provides information on the dissolved molecules or ionized particles in water. Moreover, we observed that for all experimental data regardless the temperature that we collected them, the TDS concentration decreases with the increase in pH.
Our results for the first time link dissolved matter concentration in water (TDS) with the colloidal system parameter (particle size) and provide an insight on how the colloidal system (suspended solids in water) can affect TDS concentration.