A New Laboratory Technique to Enhance Proppant Consolidation During Propped Hydraulic Fracturing Treatment

The objectives of this investigation were to perform a rock mechanical study to evaluate long term stability of Resin-Coated Proppant (RCP), combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations. Thereby providing a tool for the industry to know exactly the duration of the shut-in time before putting a well back onto production. A new experimental method was developed to monitor the curing process of RCP as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature, while the tested RCP sample was being housed in a pressurized vessel. The pressurized vessel was subjected to a variable temperature profile to mimic the recovery of the reservoir temperature following a propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize the potential for proppant flow back. The study has been performed on various types of RCP samples under a range of reservoir conditions. The role of closure stress, temperature, curing time and carrier fluids in attaining a maximum strength of RCP following a propped hydraulic fracturing treatment have been investigated. Also, the Unconfined Compressive Strength (UCS) of various types of RCP have been measured. The testing methods currently practiced in the industry to qualify proppant for field applications are based on physical characterization of several parameters such as the specific gravity of proppant, absolute volume, solubility, roundness, sphericity and bulk density. The sieve analysis, compressive strength, and API crush testing are also measured and reported. The API Recommended Practices; API RP56, API RP58 and API RP60 are the main procedures used to test the suitability of proppants for hydraulic fracturing treatment. However, there is no published API testing method for RCP; therefore this study introduces a new testing procedure, using acoustic velocity as a function of temperature and compressive strength as a function of time; to qualify a given RCP for a particular reservoir of known stress and temperature. The final outcome of this study is to establish a functional procedure for such measurements, in order to maximize the success of a propped hydraulic fracturing treatment and minimize the occurrence of flow back incidents.

Relative Permeability Behavior of Oil- Water Systems in Wolfcamp and Eagle Ford Fractures

Presently, two-phase flow behavior through propped and unpropped fractures is poorly understood, and due to this fact, reservoir modeling using numerical simulation for the domain that contains fractures typically assumes straight-line relative permeability curves and zero capillary pressure in the fractures. However, there have been several studies demonstrating that both viscous and capillary dominated flow can be expected in fractured reservoirs, where non-linear fracture relative permeabilities must be used to accurately model these reservoirs. The objective of this study is to develop an understanding of the relative permeability of oil-water systems in fractures through experimental study. The experimental measurements conducted in this study were done using downhole cores from the Wolfcamp and the Eagle Ford Shale formations. The cores were cut to 1.5-in diameter and 6-in length testing samples. The specimens are saw-cut to generate a fracture along each sample first, and then conditioned in the reservoir fluid at the reservoir temperature for a minimum of 30 days prior to any testing. Wolfcamp and Eagle Ford formation oil and reconstituted brine with and without surfactants are used as the test fluids. The measurements were recorded at effective fracture closure stress and reservoir temperature. Also, real-time measurements of density, pressure, and flow rate are recorded throughout the duration of each test. Fluid saturation within the fracture was calculated using the mass continuity equation. The oil-water relative permeability was measured using the steady-state method. All measurements were conducted at reservoir temperature and at representative effective fracture closure stress. The data from the experimental measurements was analyzed using Darcy's law, and a clear relationship between relative permeability and saturation was observed. The calculated relative permeability curves closely follow the generalized Brooks-Corey correlation for oil-water systems. Furthermore, there was a significant difference in the relative permeability curves between the oil-water only systems and the oil-water surfactant systems. The result of this study is useful for estimating the expected oil production more realistically. It also provides information about the effect of surfactants on oil-water relative permeability for optimal design of fracture fluids.

Pumping Schedule Optimization in Acid Fracturing Treatment by Unified Fracture Design

Acid fracturing simulation is used widely to optimize carbonate reservoirs and improve acid fracturing treatment performance. In this study, a method was used to minimize the risk of the acid fracturing treatment. First, optimal fracture geometry parameters with UFD methods are calculated. After that, design components change as long as fracture geometry parameters reach their optimal values. The results showed a high flow rate needed to achieve optimal fracture geometry parameters with increasing acid volume. Sensitivity analysis was performed on controllable and reservoir parameters. It observed that a high flow rate should be applied for a low fluid viscosity to achieve the optimization goals. Straight acid reaches optimal conditions at a high flow rate and low volume. These conditions for retarded acids appear only at a low flow rate and high volume. The study of the acid concentration for gelled acid showed that as it increased, the flow rate and volume increased. Besides, for low permeability formation, a large fracture half-length and small fracture width are desirable. In this case, a higher flow rate will be required. The sensitivity analysis showed that the optimum flow rate and acid volume increase and decrease for the high Young's modulus. The effect of closure stress was also investigated and observed for a sample with high closure stress, low flow rate, and high acid volume are required.

Flowback Test Analyses at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) Site

In 2017 and 2019, injection testing was carried out in three zones in a vertical well in granite at the Frontier Observatory for Research in Geothermal Energy site near Milford, Utah, USA. In several injection cycles, flowback was implemented rather than shut-in. The goal was to explore an alternative to prolonged shut-in periods for inferring closure stress, formation compressibility, and formation permeability (permeability thickness product). The flowback procedures involved a cyclic flowback/shut-in, while pressure decreased. The flowback data are presented, and analyses are shown. The inferred closure stress(es) from flowback analyses are lower than for equivalent injection cycles that were strictly shut-in. Relatively high formation compressibility obtained from the flowback analyses indicates an extensive, fractured system. This study also includes numerical simulation of the flowback events. The numerical model shows that the rebound pressure is not necessarily the lower bound of the minimum principal stress. The signature of stiffness change can be identified as the process when the depletion mainly transitions from hydraulic fracture to natural fractures from numerical analysis. Overall, flowback potentially has advantages over shut-in because of the reduced time to closure.

Efficient Modeling of Depletion Induced Fracture Deformation in Unconventional Reservoirs

The change of fracture conductivity during reservoir depletion significantly affects the well performance and stress evolution in unconventional formations. A common practice is to model fracture deformation using the traditional finite element method with very dense unstructured grids representing complex fracture geometries. However, the associated computational cost is high, so previous studies mainly use empirical correlations to catch the fracture conductivity loss or neglect fracture deformation during the production period. This work proposes a novel coupled flow and geomechanics model with embedded fracture methods to capture the fracture deformation accurately yet efficiently in unconventional reservoirs. Under a single set of structured grids, an embedded discrete fracture model (EDFM) is employed to characterize fluid flow through discrete fractures by introducing non-neighboring connections, and an extended finite element method (XFEM) is applied to simulate discontinuities over fracture walls by adding phantom nodes. In addition, a modified proppant model is incorporated to represent interactions between proppants and hydraulic surfaces, and an iterative coupling scheme is implemented to link the fracture-related fluid flow and solid mechanics. Being validated against the classical benchmark problem, the coupled model is used to investigate the impacts of proppant strength, closure stress, and bottomhole pressure on fracture deformation, well production, and in-situ stresses. Numerical results indicate that weaker proppant support induces more fracture aperture and production losses, resulting in greater stress changes and higher residual pressure in the depletion region. In comparison, the fracture deformation for a well-propped scenario is modest and barely affects the well performance and stress redistribution. Less stressed formation corresponds to lower closure stress on fracture walls, which triggers limited fracture closure and stabilizes well production. Moreover, a moderate bottomhole pressure decline rate avoids significant fracture closure while preserves relatively high initial production rates. The coupled flow and geomechanics model with embedded fracture methods resolves computational difficulties in modeling complex fracture deformations and delivers more insights on production forecast and stress changes crucial to refracturing and infill operations.

Axial Fracture Initiation During Diagnostic Fracture Injection Tests and Its Consequences on Interpretations

Diagnostic fracture injection tests (DFIT) are used widely in the unconventional reservoirs to obtain formation properties. These properties can be crucial in optimizing primary and infill completions. The interpretation methods are assuming that pumping fluid would create a single planar fracture, however, perforation frictions and near wellbore stress concentration may accommodate initiation of fractures along the casing first (axial fractures). The possibility of the formation of an axial fracture increases in high injection rates and low differential stresses. In this study, we investigate the effect of the formation of an additional axial fracture on a DFIT test and its interpretation, using a fully coupled geomechanics and fluid flow model. We provide a model for the initiation and closure of axial and transverse fractures during the process. We also demonstrate that the estimate of the closure stress can be misleading when presence of an additional axial fracture is ignored. Finally, we discuss a potential method to determine the maximum horizontal stress under such circumstances. In fact, the variations in cement quality, cement type and its placement play roles in linking of adjacent perforations and form axial fractures, therefore it might be difficult to establish a safe perforation design to avoid initiation of axial fractures, but we can adjust our analysis to incorporate axial fractures effect.

Micromechanical Modeling Tension-Compression Fatigue Hysteresis Loops Model of Fiber-Reinforced Ceramic-Matrix Composites Considering Fibers Failure

In this paper, a micromechanical tension-compression fatigue hysteresis loops model of fiber-reinforced ceramic-matrix composite (CMC) was developed considering fibers failure. Multiple fatigue damage mechanisms of fibers failure, interface debonding, slip and wear, and matrix fragmentation were considered and incorporated in the micromechanical fatigue hysteresis loops model. Upon unloading, the unloading stress-strain relationship was divided into three stages, including, (1) Unloading Stage I: the unloading interface counter slip stage and the unloading stress is between the tensile peak stress and the matrix crack closure stress; (2) Unloading Stage II: the unloading partial compressive stage and the unloading stress is between the matrix crack closure stress and the unloading complete compressive stress; and (3) Unloading Stage III: the unloading complete compressive stage and the unloading stress is between the unloading complete compressive stress and the compressive valley stress. Multiple micromechanical damage parameters of fibers failure probability, unloading/reloading transition stress, closure stress of the matrix cracking, compressive transition stress, complete compressive stress, unloading/reloading inverse tangent modulus (ITM), and interface counter slip/new slip ratio (ICSR/INSR) were adopted to characterize the tension-compression stress-strain hysteresis loops. Experimental tension-compression fatigue stress-strain hysteresis loops of unidirectional CMCs were predicted using the developed micromechanical models. The characteristics of the tension-compression fatigue hysteresis loops of unidirectional CMC are analyzed for different material properties, damage state, and tensile fatigue peak stress.

STRESS MEASUREMENT CAMPAIGN IN SCIENTIFIC DEEP BOREHOLES: FOCUS ON TOOL AND METHODS

As part of the Sectoral Plan for Deep Geological Repositories, three candidate sites are currently examined by a focused geological exploration program in Northeastern Switzerland. The program involves 3D seismic surveys and drilling of at least two deep boreholes at each site. Stress testing is being undertaken with a wireline formation testing tool in each borehole (around 20 stress tests per borehole). Improvements in the toolstring were introduced step by step to sharpen the range of the stress estimates and enable 100% coverage of the desired lithological column. This is the first time that a single toolstring with three packers has been run to perform the complete combination of sleeve fracturing, hydraulic fracturing and sleeve reopening tests. A dedicated stress testing protocol was developed to ensure the most robust estimate of the stress in a large variety of formations. A detailed planning process has been developed to maximize the success rate and coverage of stress test stations, integrating all available information as it becomes available. A review of the techniques enabled by the new toolstring for estimating the closure stress from a stress test, especially in low-permeability formations, is presented, and detailed stress testing examples are provided. Preliminary comparison between the stress estimates for the first two boreholes in the campaign are shown.

Characterization of an electrically conductive proppant for fracture diagnostics

Fracture diagnosis with electromagnetic (EM) and electrical tools requires proppants with high electrical conductivity and mechanical strength. Lab measurements of the electrical and hydraulic conductivity of proppants are critical for selecting the best candidates. Such measurements greatly benefit simulations, field tests, and the ultimate application of such proppants in the field. To that end, a new lab protocol is developed for measuring the electrical and hydraulic conductivity of proppants. The lab setup, which mainly includes a resistivity core holder and a Hassler sleeve core holder, allows for simulation of realistic pressure and temperature conditions when making measurements. Petroleum coke (PC) is proposed as a candidate proppant because of its widespread availability and low cost. Lab measurements show that the effective electrical conductivity of pure PC in a model fracture is approximately 5000 S/m, under a closure stress greater than [Formula: see text] (4000 psi). When PC is mixed with sand, the effective electrical conductivity of the mixture decreases with an increasing weight percentage of sand. Although sand degrades the contact between PC particles, the electrical conductivity stays reasonably high (approximately 1700 S/m) when 50% sand is added. Hydraulic conductivity measurements show that when a fracture is propped with pure PC, the measured fracture conductivity is greater than [Formula: see text] ([Formula: see text]) (dimensionless fracture conductivity greater than 100 for a shale with [Formula: see text] or 100 nD permeability) under a confining pressure of [Formula: see text] (6000 psi). This means that a fracture propped with PC is infinitely conductive in a typical shale formation. When sand is added, the fracture’s hydraulic conductivity becomes even higher, which clearly shows PC’s ability of sustaining high stresses. The proposed protocol provides a robust and effective method that can be generalized for lab testing for other candidate proppants. The data presented clearly show that PC has the potential for field-scale applications in EM hydraulic fracture diagnostics.

Creep hardening damage constitutive model of coal with fracture proppant

Fracture is the flow channel of gas (fluid) body in the exploitation of coalbed methane and other energy sources. It has a great influence on gas (fluid) production and work efficiency. Creep results in the proppant embedded in the coal seam leading to fracture damage, reducing fracture permeability. However, there are few studies on a creep model considering proppant embedding in fractures. In this paper, a creep test of proppant embedment in a fracture of a coal seam is carried out, and a creep model considering the damage to proppant embedment is established. The results show that with an increase of closure stress, the range of strain rate first increases and then decreases, and the mean value of strain rate increases slowly and then increases rapidly when the closure stress levels increases in the stable creep stage. During the creep of coal with a fracture proppant, there is not only the hardening and damage of coal, but there is also the damage to proppant embedding. A creep hardening damage model considering the viscosity damage factor of coal, the stress hardening model, the elastic-plastic damage factor, proppant compaction and the embedded viscosity loss factor is established. The creep hardening damage model can better describe the whole process of decelerating creep, stable creep and accelerating creep of coal with proppant fracture.