bluuebunny/crossref_metadata_2025_split huggingface dataset:
Examining the Impact of Hydrocarbon Drainage on Completion and In-Fill Drilling Strategies in Unconventional Reservoirs
Authors: Srinivasan Karthik , Gbededo Midowa , Hue Hongxue , Krishnamurthy Jayanth , Gonzales Veronica 
Published: February 2021

Abstract
Evaluating the effects of asymmetric stress distribution around a lateral can greatly help optimize completion techniques and overall production from in-fill horizontal wells in unconventional shale and tight reservoirs. Several factors affect long-term production from in-fill drilled wells including but not limited to pressure depletion from produced wells, change of effective stresses in the depleted formation and interference between hydraulic fractures when the new in-fill wells are drilled, stimulated and brought into production.
The study addresses a variety of key challenges that the unconventional oil and gas industry is looking to understand. These include understanding: How the presence of a depleted wellbore affects hydraulic fracture propagation from a nearby newly drilled wellHow refracturing considerations in a producing well are affected by hydrocarbon drainage and modified stress contrastsHow fracturing/refracturing pumping designs and volumes should be optimized to address the challenges surrounding the wellbore
Under circumstances mentioned above, pressure distribution around the wellbore from hydrocarbon drainage was estimated by history matching production data over a certain period of time. Then the impact of various types of fracturing treatments on pressure depletion profiles from offset wells was studied using a fully numerical fracture simulator that is capable of handling asymmetric stress distribution around the lateral. Fracture geometries from this study were either asymmetric due to depletion on only one side of the lateral or longer due to increased stress contrast. These fracture geometries were fed to a production model to forecast long-term production from in-fill wells and study drainage patterns over time. Understanding these challenges provided a sub-surface perspective of how completion techniques should be optimized to get maximum hydrocarbon recovery from reservoirs consisting of laterals that have already been on production.
Overcoming Obstacles for Produced Water in Bakken Well Stimulations
Authors: Schmidt Darren D. , Statoil P.E. , MacKay Bruce , Williams Brandon , Beck Frederick , Bell Adam , McMahon Blake , Bradley Heather , Lian Eric Gin 
Published: February 2021

Abstract
The use of produced water in well stimulation is not straightforward and presents numerous challenges. A case study using 100% produced water from the Bakken Formation to stimulate a two-well pad in Williams County North Dakota is presented. The well stimulations include a typical 30-stage plug & perf completion using a hybrid fluid design consisting of slickwater and crosslinked gel. The pad includes both a Middle Bakken horizontal and a Three Forks horizontal well. This case study addresses the challenges and obstacles faced over a two-year period since embarking on the first field experiment using 50% produced water to stimulate a well in the same area. A number of first-time experiences have been addressed in the areas of cost, fluid chemistry, water quality, facilities, logistics, storage, and regulatory. All of these factors appeared to be insurmountable barriers in the early phases of considering the use of produced water for well stimulation. However over time and with careful developments along the way, we have progressed to the point of practicality for such endeavors. This case study presents the barriers, technical issues, technology development, current practice, and expected progress of produced water stimulation in the Williston Basin.
Role of Turbulent Flow in Generating Short Hydraulic Fractures with High Net Pressure in Slickwater Treatments
Authors: Ames Brandon C. , Bunger Andrew P. 
Published: February 2021

Abstract
This paper provides an argument for considering turbulent flow for hydraulic fracturing using slickwater in shale reservoirs. It shows that the tendency of models that assume laminar fluid flow to over-predict fracture length and under-predict net pressure can be corrected by instead recognizing that the flow regime is turbulent for high rate, water-driven hydraulic fractures. Firstly, we provide a rationale supporting the appropriateness of assuming turbulent flow. Then, using a Perkins-Kern-Nordgren (PKN) fracture model and parameters similar to slickwater treatments in shale reservoirs, we show that the laminar flow model overpredicts fracture length and underpredicts fracture width and net pressure, compared to the turbulent flow model. The result, if indeed a hydraulic fracture grows in the turbulent fluid flow regime, is that matching the length with the laminar model requires input of an unreasonably large leak-off coefficient, resulting in an exacerbation of the underprediction of the wellbore pressure. On the other hand, the turbulent model is shown to be able, in principle, to account for short, high pressure hydraulic fractures without resorting to inflating the leak-off coefficient or compromising the calibration of the model to the wellbore pressure.
Arbitrary Fracture Propagation in Heterogeneous Poroelastic Formations Using a Finite Volume-Based Cohesive Zone Model
Authors: Bryant Eric C. , Hwang Jongsoo , Sharma Mukul M. 
Published: February 2021

Abstract
A finite volume-based arbitrary fracture propagation model is used to simulate fracture growth and geomechanical stresses during hydraulic fracture treatments. Single-phase flow, poroelastic displacement, and in-situ stress tensor equations are coupled within a poroelastic reservoir domain, using a fixed-strain split assumption. The domain is idealized as two-dimensional and plane-strain, with heterogeneous elastic material and fracture toughness properties. Fracture propagation proceeds by failure along finite volume cells in excess of a threshold effective stress. The cohesive zone model (CZM) is used to simulate propagation of non-planar fractures in heterogeneous porous media under uniform, anisotropic stresses. In addition the model computes the stress field and the pore pressure in the rock matrix to account for stress interference effects. This allows us to estimate the simulated micro-seismic signature of the rock during fracturing. Results show that the presence of bedding planes or planes of weakness in the rock can lead to complex fracture trajectories. The growth of multiple, non-intersecting, competing fractures is also simulated. It is shown that the fracture geometry obtained using this model is highly dependent on the pattern of heterogeneity. For homogeneous reservoirs and a high in-situ stress contrast, planar fractures are obtained. As the stress contrast is decreased and the degree of heterogeneity is increased, fracture complexity increases. Results for different kinds and levels of formation heterogeneity; planes-of-weakness such as bedding planes or natural fracture networks, and layers with different mechanical properties are presented. This model allows for first-of-kind simulation of fracture propagation with arbitrary geometry in a poroelastic solid domain, using proven computational finite volume methods (FVM). The effect of fluid backpressure, mechanical stress shadow effects, and formation heterogeneity are accounted for. The importance of critical stresses on fracture path is discussed.
Completing the Second Target: Finding Optimal Completion Practices for the Three Forks Formation in the Williston Basin Using Multivariate Statistical Analysis
Authors: Williams Brandon , Weaver Brian , Weijers Leen 
Published: February 2021

Abstract
The Three Forks Formation in the Williston Basin has started to see a large increase in activity in the past six years. This is largely due to the shallower Bakken Formation transitioning into an infill development mode and operators looking at finding incremental reserves from the Three Forks Formation below. The objective of this paper is to evaluate the geological and completion variables of Three Forks horizontal wells in the North Dakota portion of the Williston Basin, and show which factors impact production performance using multivariate statistics. A financial evaluation of the completion factors will also be presented to show which variables have the biggest impact on production.
A database of available completion and geological data has been assembled from the North Dakota Industrial Commission (NDIC) website. To date there are roughly 2,400 horizontal wells targeting the Three Forks Formation on the North Dakota side of the Williston Basin. Some of the variables collected include number of fracture stages, amount and type of proppant, total volume and type of frac fluid, lateral length, max treatment pressure and rate, API oil gravity, formation thickness (from formation tops) and production. The data was subjected to multivariate nonlinear statistical analysis. This type of analysis allows for simultaneously comparing multiple variables to one outcome variable. In this case study the outcome variable is 180-day production.
Using multivariate analysis in the Three Forks Formation of the Williston Basin will aid in predicting production in different parts of the basin and finding which controllable completion variables have the most significant impact on production. The output can also aid in production forecasting based on changes to treatment designs.
From the Laboratory to the Field: Successful Multistage Horizontal Fracturing Design and Implementation in Tight Sandstones in the Anadarko Basin
Authors: Abrams Megan E. , Churcher Peter L. , Piland James R. , Grieser Bill , Squires Scott , Crane Brady 
Published: February 2021

Abstract
This paper discusses the re-engineering of a fracturing design targeting tight oil in horizontal wells drilled in the Pennsylvanian-age Tonkawa sandstones, located in Dewey County, Oklahoma, through the integration of laboratory, geological, petrophysical, fracture simulation, and diagnostic fracture injection test (DFIT) analysis.
Laboratory testing, which included thin section and scanning electron microscopy (SEM), X-ray diffraction (XRD), and mercury injection capillary pressure (MICP) analyses, was conducted to determine mineralogy, nature of the pore body geometry, and potential damage mechanisms. Fracturing fluid chemistry was tested and optimized using both cuttings and core plugs from representative reservoir rock.
Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple combo and full wave sonic logs were combined with geological parameters and potential treating schedules to develop sophisticated fracture simulation models. These models were then refined with in-situ reservoir data obtained from DFIT analyses conducted using downhole gauges to derive the final fracturing treatment design.
The integration of all available data allowed moving away from a “one-size-fits-all” fracture design to one tailored specifically to the targeted reservoir rock. The net result was an optimized fracture design that helped reduce both cost and formation damage, thus improving flowback, long-term productivity, and profitability from these tight sandstones.
A similar fracturing design process is being developed for other tight sandstone reservoirs in the Anadarko basin, with preliminary results confirming that each formation requires a unique fracturing treatment design to be effective.
Use of a CO2-Hybrid Fracturing Design to Enhance Production from Unpropped Fracture Networks
Authors: Ribeiro Lionel H. , Li Huina , Bryant Jason E. 
Published: February 2021

Abstract
This paper introduces a new CO2-hybrid fracturing fluid design that intends to improve production from ultra-tight reservoirs and reduces freshwater usage. The design consists of: (1) injecting pure CO2 as the pad fluid to generate a complex fracture network, and (2) injecting a gelled slurry (water- or foamed-based) to generate near-wellbore conductivity. The motivation behind this design is that while current aqueous fluids provide sufficient primary hydraulic fracture conductivity back to the wellbore, they under-stimulate the reservoir and leave behind damaged stimulated regions deeper in the fracture network. Much of that (unpropped) stimulated area is ineffective for production due to interfacial tension effects, fines generation, and/or polymer damage. We present simulation work that demonstrates how CO2, with its low viscosity, can extend the bottom-hole treating pressure deeper in the reservoir and generate a larger producible surface area. We also present experimental evidence that CO2 leaves behind higher unpropped fracture conductivities than slick water. This paper does not address the many operational and logistical challenges of using CO2 as a fracturing fluid. Rather, it intends to demonstrate the production uplift potential of the proposed design, which seems particularly attractive in reservoirs capable of sustaining production from unpropped fractures (e.g., reservoirs with low stress anisotropy, high Young's modulus, and a pervasive set of natural fractures).
On Liability Issues Concerning Induced Seismicity in Hydraulic Fracturing Treatments and at Injection Disposal Wells: What Petroleum Engineers should know
Authors: Hall K. , Dahi Taleghani A. , Dahi Taleghani N. 
Published: February 2021

Abstract
The rates of oil and natural gas production in the United States have increased dramatically during the past decade, largely due to the use of hydraulic fracturing and horizontal drilling. This has benefitted the U.S. economy and generated hopes that the “shale revolution” could be replicated elsewhere. At the same time, however, public concern has grown regarding potential adverse impacts that fracing or other operations like gas flooding, waterflooding, waste disposal, and other production processes may have. One of the main public concerns relates to induced seismic events – that is, man-made earthquakes. Geologists have concluded that a variety of human activities can induce seismic events. Such operations include the operation of injection disposal wells, though a relatively small fraction of such wells are suspected of inducing seismic activity. Further, available public data shows that, on very rare occasions, hydraulic fracturing itself has caused tangible seismic activity. Although such events have been uncommon, they have attracted significant public attention and strengthened the opponents of oil and gas development. Further, although seismic events induced by oil and gas activity appear to have caused little damage, the potential legal liability could be substantial if such an event ever caused significant damage. Accordingly, industry should give increased attention to minimizing the likelihood of such events. The paper provides context for this issue by briefly reviewing information regarding recent cases of induced seismic activity, current technology for monitoring these events, and the inherent limitations in measurements and interpretation involved in using these techniques. This paper also discusses techniques that operators can use to reduce the likelihood of induced seismic events at hydraulic fracturing sites and at injection disposal wells. These include use of pretreatment geomechanical analyses to assess the likelihood of significant seismic events and, in appropriate circumstances, to guide a modification in perforation clusters design to reduce the likelihood of nearby fault reactivations. Finally, the article provides additional context by discussing relevant laws, including regulatory responses to suspected events of induced seismic activity and the possible legal theories for imposing liability for such events. The new regulations will compel operators to take certain actions and the potential for legal liability may incentivize additional action.
A Cohesive Model for Modeling Hydraulic Fractures in Naturally Fractured Formations
Authors: Gonzalez M. , Taleghani A. Dahi , Olson J. E. 
Published: February 2021

Abstract
A cohesive zone model (CZM) has been developed to couple fluid flow with elastic, plastic and damage behavior of rock during hydraulic fracturing in naturally fractured formations. In addition to inelastic deformations, this model incorporates rock anisotropies. Fracture mechanics of microcrack and micro-void nucleation and their coalescence are incorporated into the formulation of the CZM models to accurately capture different failure modes of rocks. The performance of the developed elastoplastic and CZM models are compared with the available data of a shale play, and then the models are introduced into a commercial finite element package through user-defined subroutines. A workflow to derive the required model parameters for both intact rock and cemented natural fractures is presented through inverse modeling of field data. The hydraulic fractures' growth in the reservoir scale is then simulated, in which the effect of fluid viscosity, natural fracture characteristics and differential stresses on induced fracture network is studied. The simulation results are compared with the available solutions in the literature. The developed CZM model outperforms the traditional fracture mechanics approaches by removing stress singularities at the fracture tips, and simulation of progressive fractures without any essential need for remeshing. This model would provide a robust tool for modeling hydraulic fracture growth using conventional elements of FEA.
Correlation and Interpretation of Microseismic Responses using Pressure Measurements in Offset Observation Wells
Authors: Downie Robert , Calvez Joel Le , Dean Barry , Rutledge Jeff 
Published: February 2021

Abstract
Interpretation of the microseismic data acquired during hydraulic fracture treatments is based on a variety of techniques that make use of the locations, times, and source parameters of the detected events, in conjunction with the stimulation treatment data. It is sometimes possible to observe trends or changes in the microseismic data that correspond to the surface pressure measurements; however this aspect of interpretation becomes problematic due the variability of fluid friction, slurry density, perforation restrictions, and other near-wellbore pressures when computing bottom hole fracturing pressure.
An interpretation technique is proposed that uses pressure measurements in observation wells that are offset to the treatment well during microseismic interpretations. The observation well can be any well with open perforations in close proximity to the treatment well. The observation well pressures are not affected by the many complicating factors that are encountered when estimating pressure in the fracture from the surface pressure measured in the treatment well.
Example data from field observations are used to demonstrate that the detection of microseismic events near an observation well and corresponding detection of fluid pressure from the fracture in the observation well validates the calculated event locations. The relationship between fracture pressure, the state of stress, and microseismic responses is discussed using Mohr-Coulomb failure criteria. Observation-well pressures and microseismic events are also used to identify instances where reservoir pressure depletion near the observation well affects surface operations at the treatment well.
The results of the study show that reliable measurements of fracture pressure for use in microseismic interpretations can be obtained from offset observation wells, and where reservoir pressure depletion causes deviations from expected fracture behavior. The results also show that microseismic responses are directly related to fracture pressure, and not simply the presence of fracturing fluid itself, leading to an improved understanding of the conditions under which microseismic events occur.
Acid Fracturing Shales: Effect of Dilute Acid on Properties and Pore Structure of Shale
Authors: Wu Weiwei , Sharma Mukul M. 
Published: February 2021

Abstract
Many microfractures created during hydraulic fracturing are too small to be filled with proppants and are likely closed during production. However, for some shales that are rich in calcite (calcareous mudstones), such as the Bakken and Eagle Ford shale, dilute acids can be used while fracturing to maintain the conductivity of these microfractures under closure stress by non-uniformly etching the fracture surfaces. The mineralogy and pore structure of the shale and their evolution during acid fracturing are critical factors on the surface surface etching profile and the fluid leakoff. Therefore, understanding how acid dissolution changes the microstructure, petrophysical properties and pore structures of shale is essential in the design and application of acid fracturing in shales.
In this paper changes in shale properties and pore structure by acid fracturing were demonstrated and visually observed for the first time with a scanning electron microscope. Acidized sections of a shale core sample were carefully isolated, and its microstructure, pore structure and petrophysical properties were systematically studied and compared with non-acidized sections of the core.
Microstructure changes were found to be strongly dependent on mineral distribution, and several patterns were identified: channels developed in carbonate-rich regions; cavities or grooves formed in carbonate-rich islands or carbonate rings; and surface roughness was created in mixed zones of scattered carbonate and inert minerals. Inert minerals such as clay, organic matter stay relatively undisturbed in the structure, while some mineral grains can be dislodged from their original locations by dissolution of the surrounding carbonates. Many macropores with size up to 120 µm were created and mesopores mostly associated with clay gained more accessibility. Significantly increased permeability and porosity was measured in an acidized shale matrix. Brinell hardness measurements show that, as expected, the hardness of the shale was reduced by acidizing. This means that for acidizing to work effectively, it is important to not etch the fracture surfaces uniformly. Doing so will result in a reduction in the fracture conductivity under stress. The microstructure changes introduced by acid fracturing demonstrated in this study will result in the formation of surface asperities which is likely to improve the fracture conductivity of induced unpropped fractures. The acidized shale matrix close to the fracture surface with increased abundance of macropores and accessibility to mesopores may serve as a preferred pathway for fluid flow as well.