Geomechanical Controls on Frac-Hits

The communication among the horizontal wells or "frac-hits" issue have been reported in several field observations. These observations show that the "infill" well fractures could have a tendency to propagate towards the "parent" well depending on reservoir in-situ conditions and operational parameters. Drilling the horizontal wells in a "staggered" layout with both horizontal and vertical offset could be a mitigation strategy to prevent the "frac-hits" issue. In this study, we present a detailed geomechanical modeling and analysis of the proposed solution. For numerical modeling, we used our state-of-the-art fully coupled poroelastic model "GeoFrac-3D" which is based on the boundary element method for the rock matrix deformation/fracture propagation and the finite element method for the fracture fluid flow. The "GeoFrac-3D" simulator fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The simulation results demonstrate that production from a "parent’ well causes a non-uniform reduction of the reservoir pore pressure around the production fractures, resulting in an anisotropic decrease of the reservoir total stresses, which could affect fracture propagation from the "infill" wells. We examine the optimal orientation and position of the "infill" well based on the numerical analysis to reduce the "frac-hits" issue in the horizontal well refracturing. The posibility of "frac-hits" can be reduced by optimizing the direction and locations of the "infill" wells, as well as re-pressurizing the "parent" well. The results suggest that arranging the horizontal wells in a "staggered" or "wine rack" arrangement decreases direct well interference and could increase the drainage volume.

Prediction Analysis of Induced Casing Deformation of Horizontal Well in Fractured Shale Reservoir: Case Study of Weiyuan Gasfield

Casing deformation (CD) is a major challenge for shale gas development in Weiyuan gasfield, natural fracture (NF) slippage is one of the main causes of CD in Weiyuan gas filed. In order to study the mechanism and regularity of NF slippage induced CD, a wellbore shear stress calculation model and a CD degree prediction model are established. And results show that, the approach angle and ground principal stress difference have significant influence on wellbore shear stress, high wellbore shear stress occurs when wellbore orientation is perpendicular to the NF trend. Wellbore shear stress increases with the increase of fracture fluid pressure and NF area, improving casing strength or cementing quality has limited effect on reducing the risk of CD. The smaller the young's modulus, the higher the CD degree, Poisson's ratio has limited effect on CD degree. NF approach and fracture fluid pressure determines the value of CD degree. Field case shows that reasonable fracturing technology to control fracture net pressure and wellbore position arrangement are helpful for reducing CD risk, and the model proposed in this paper can be used to predict CD risk and calculate the CD degree.

Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

Study on gelation, temperature resistance and micromorphology of modified nano-ZrO2 crosslinked hydroxypropyl guar gum

In order to improve the temperature and shear resistance of fracturing fluid, a kind of nano-zirconium-boron crosslinker, which is different from the traditional zicral-boron crosslinker, is prepared using 4wt% borax, 50 v/v% glycerol, 8 v/v% triethanolamine and 40 v/v % acetylacetone as raw materials, and its chemical structure is characterized of by infrared spectroscopy and its performance, such as viscoelasticity, temperature and shear resistance and gel breaking property, have also been evaluated. The results show that firstly the elastic modulus of the fracturing system is much larger than the viscous modulus at frequency of 0.1–10 Hz, indicating that the fluid is a typical structural fluid. Secondly the fracture fluid crosslinked by nano-zirconium-boron crosslinker is sheared at 180 °C, 170 s−1 for 2 h, and the viscosity is maintained above 60 mPa.s. Finally viscoelasticity, gel breaking property and damage evaluation also meet the requirements of national standard code for Chinese. Analysis of the temperature resistance mechanism of the HPG fracturing fluid crosslinked by nano-zirconium-boron crosslinker shows that its connecting lines are thicker and stronger to make the fracturing fluid have better temperature and shear resistance.

Proppant Transport Using High-Viscosity Friction Reducer Fracture Fluids at High-Temperature Environment

Summary The stimulation of unconventional reservoirs to improve oil productivity in tight formations of shale basins is a key objective in hydraulic fracturing treatments. Such stimulation can be made by reliable fracture fluids that have a high viscosity and elasticity to suspend the proppant in the fracture networks. Recently, due to several operational and economic reasons, the oil industry began using high-viscosity friction reducers (HVFRs) as direct replacements for linear and crosslinked gels. However, some issues can limit the capability of HVFRs to provide effective sand transport, including the high fluid temperature during fracture treatment inside the formations. This may lead to unstable fracture fluids caused by a decrease in the interconnective strength between the fluid chains, which results in reduced viscosity and elasticity. This study comprehensively investigated HVFRs in comparison with guar at various temperatures. An HVFR at 4 gallons per thousand gallons of water (gpt) and guar at 25 pounds per thousand gallons of water (ppt) were selected based on fluid rheology tests and hydraulic fracture execution field results. The rheological measurements of both fracture fluids were conducted at different temperature values (i.e., 25, 50, 75, and 100°C). Static and dynamic proppant settling tests were also conducted at the same temperatures. The results showed that the HVFR provided better proppant transport capability than the guar. The HVFR had better thermal stability than guar, but its viscosity and elasticity decreased significantly when the temperature exceeded 75°C. An HVFR can carry and hold the proppant more deeply inside the fracture than liner gel, but that ability decreases as the temperature increases. Therefore, using conditions that mimic field conditions to measure the fracture fluid rheology, proppant static settling velocity, and proppant dune development under a high temperature is crucial for enhancing the fracture treatment results.

Development of a Fracturing Nanofluid with Dual Purpose: Increasing Heavy Oil Mobility and Reducing the Reservoir Damage Associated at the Remaining Fracture Fluid

This work aims to develop a fracturing nanofluid with a dual purpose: i) to increase heavy crude oil mobility and ii) to reduce formation damage caused by the remaining fluid. Three commercial nanoparticles were evaluated: two fumed silica of different sizes and one type of alumina. They were acidified and basified, obtaining nine nanoparticles (NPs) by the surface modification, characterized by TEM, DLS, Z Potential and Total Acidity. The effect of adding nanoparticles at different concentrations onto the linear gel and heavy crude oil was determined by their rheological behavior. Also, there was assessed the alteration of the rock wettability by contact angle for all NPs and concentrations. Based on these results, the nanoparticle with better performance was the neutral fumed silica of 7 nm at 1000 mg/L. These were used to make a fracturing nanofluid from a commercial fracturing fluid (FF). Both of them were evaluated through their rheological behavior overtime at high pressure following the API RP39 test and quantitative measurements of the rock sample wettability changes. Displacement tests also were performed on proppant and rock samples at reservoir conditions: pressure and temperature. Finally, there was evaluated the rheological behavior of the crude oil recovered in the displacement test. It was possible to conclude that the inclusion of nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation. An alteration of the rock wettability was achieved, where the rock sample became up to 50% more wettable to water. Moreover, there was a diminution of 53% in the damage caused by the remaining fracturing fluid to the oil effective permeability in the proppant medium. In the rock sample, a decrease of 31% of this kind of damage was observed. Increases of 28 and 18 % in the crude oil recovery were noticed in the proppant and the rock sample, respectively. Finally, there was a reduction of 40% in the crude oil viscosity, showing the effectiveness of adding nanoparticles to fracturing fluids for increasing oil mobility and reducing the formation damage.

Modeling the effects of fracture infill on frequency-dependent anisotropy and AVO response of a fractured porous layer

In a fractured porous hydrocarbon reservoir, wave velocities and reflections depend on frequency and incident angle. A proper description of the frequency dependence of amplitude variations with offset (AVO) signatures should allow effects of fracture infills and attenuation and dispersion of fractured media. The novelty of this study lies in the introduction of an improved approach for the investigation of incident-angle and frequency variations-associated reflection responses. The improved AVO modeling method, using a frequency-domain propagator matrix method, is feasible to accurately consider velocity dispersion predicted from frequency-dependent elasticities from a rock physics modeling. And hence, the method is suitable for use in the case of an anisotropic medium with aligned fractures. Additionally, the proposed modeling approach allows the combined contributions of layer thickness, interbedded structure, impedance contrast and interferences to frequency-dependent reflection coefficients and, hence, yielding seismograms of a layered model with a dispersive and attenuative reservoir. Our numerical results show bulk modulus of fracture fluid significantly affects anisotropic attenuation, hence causing frequency-dependent reflection abnormalities. These implications indicate the study of amplitude versus angle and frequency (AVAF) variations provides insights for better interpretation of reflection anomalies and hydrocarbon identification in a layered reservoir with vertical transverse isotropy (VTI) dispersive media.

Radar Imaging of Fractures and Voids behind the Walls of an Underground Mine

2-D and 3-D rock-penetrating radar data were acquired on the wall of a pillar in an underground limestone mine. The objective was to test the ability of radar to image fractures and karst voids and to characterize their geometry, aperture, and fluid content, with the goal of mitigating mining hazards. Strong radar reflections in the field data correlate with fractures and a cave exposed on the pillar walls. Large pillar wall topography was included in the steep-dip Kirchhoff migration algorithm because standard elevation corrections are inaccurate. The depth-migrated 250 MHz radar images illuminate fractures, karst voids, and the far wall of the pillar up to ~25 m depth into the rock, with a spatial resolution of lt;0.5 m. Higher-frequency radar improved image resolution and aided the interpretation, but at the cost of shallower depth of penetration and extra acquisition effort. Due to the strong contrast in physical properties between rock and fracture fluid, fractures with apertures as thin as a fiftieth of a radar wavelength were imaged. Water-filled fractures with mm-scale aperture and air-filled fractures with cm-scale aperture produce strong reflections at 250 MHz. Strong variation in reflection amplitude along each fracture is interpreted to represent both variable fracture aperture and non-planar fracture structure. Fracture apertures were quantitively measured, but distinguishing water- from air-filled the fractures was not possible due to the complex radar wavelet and fracture geometry. Two conjugate fracture sets were imaged. One of these fracture sets dominates rock mass stability and water inrush challenges throughout the mine. All of the detected voids and a large cave are at the intersection of two fractures, indicating preferential water flow and dissolution along conjugate fracture intersections. Detecting, locating, and characterizing fractures and voids prior to excavation can enable miners to mitigate potential collapse and flood hazards before they occur.

Novel Learnings of Proppant Transport Behavior in Unconventional Hydraulic Fractures

Effective and economic proppant placement has been one of the key objectives of hydraulic fracturing. Different proppant & fracture fluid characteristics, and placement methodologies have been historically applied based on learnings from standard proppant transport studies with parallel plate slots. The standard test setup represents a simplified planar fracture with constant width and confined height, incorporating only basic flow characteristics, and thus, is incapable of capturing unique phenomena of proppant transport in unconventional reservoirs. In this study, proppant transport laboratory tests were conducted on a large-scale (10 ft × 20 ft) tortuous slot flow system. This novel setup incorporates many significant unconventional fracture features, including lateral and vertical tortuosity, variable width, leak-off, fluid dynamics replicating upward fracture growth, etc. Proppant transport behavior was investigated for multiple parameters such as proppant size, density and concentration; fracture fluid type and viscosity; pumping sequence; pump rate; and fracture properties (width, leak-off location and rate, fracture tortuosity profile, flow directions). The detailed parametric and integrated study of test results includes analysis of proppant dune evolution, dune shape, particle size distribution across dune, propped area, fluid, and proppant collected from leak-off and exit ports. Multiple unique phenomena occurring at tortuous interfaces were observed, including the generation of isolated pockets of proppant pack, restriction of upward movement due to proppant bridging, and creation of discontinuous and sparsely distributed proppant pillars above the dune. The test results demonstrated a larger proppant dune angle in front of the dune peak during injection and a subsequent fall-off of proppant pack with a higher percentage of smaller mesh proppant back filling the area at and near the inlet (analogous to the wellbore). Self-segregation of proppant in slickwater as per mesh size resulted in higher percentage of smaller mesh proppant settled near the injection point, and a higher percentage of larger mesh proppant placed farther in the system. These observations and novel learnings highlight that it is critical to account for tortuous fracture pathway, leakoff effects and flow directions (both lateral and upward) to better understand proppant transport behaviors in unconventional fractures. A partially proppant-filled fracture area is recognized in unconventional fracture in addition to general classification of propped and unpropped fracture area. Utilizing proppant with large mesh size distribution range or pumping smaller mesh proppant first in slickwater helps achieve dual benefits of higher near wellbore conductivity and improved far-field transport. This study demonstrates and physically verifies unique proppant transport behaviors in unconventional hydraulic fractures. It also provides novel learnings that will help the industry to optimize hydraulic fracture design through the selection of optimum proppant and fluid properties with enhanced pumping strategies for overall well productivity improvement in an unconventional reservoir.