Fiber Optic Deployed Behind Cemented Casing in a Vertical Deep Tight Gas Well Used to Enhance Hydraulic Fracturing, Monitoring and Diagnostics

The use of fiber optic (FO) to obtain distributed sensing be it Distributed Temperature Sensing (DTS), Distributed Acoustic Sensing (DAS) or Distributed Strain Sensing (DSS) is a well & reservoir surveillance engineer's dream. The ability to obtain real-time live data has proven useful not only for production monitoring but during fracture stimulation as well. A trial the first of its kind in Petroleum Development Oman (PDO) used fiber optic cable cemented in place behind casing to monitor the fracture operations. Several techniques are used to determine fracture behaviour and geometry e.g. data fracs, step down test and after closure analysis. All these use surface pressure readings that can be limited due to uncertainty in friction pressure losses and the natural complexity in the formation leading to very different interpretations. Post frac data analysis and diagnostics also involves importing the actual frac data into the original model used to design the frac in order to calibrate the strains (tectonics), width exponent (frac fluid efficiency) and the relative permeability. Monitoring the frac using DAS and DTS proved critical in understanding a key component in fracture geometry; frac height. The traditional method to determine fracture height is to use radioactive tracers (RA). But these are expensive and the data only available after the job (after drilling the plugs and cleaning the wellbore). In contrast fiber optic can provide real time data throughout the frac stages including the proppant free PAD stage which tracers can't. The comparison of DTS and Radioactive Tracers showed very good agreement suggesting that DTS could replace RA diagnostic. Hydraulic fracture stimulation operations in well-xx was the first one of its kind to be monitored with fiber optic. The integrated analysis of the available logs allowed us to benchmark various information and gain confidence in the conclusions. This helped fine tune the model for future wells for a more optimized zonal targeting and hydraulic fracture design. In this paper we will share the detailed evaluation of the fracture propagation behaviour and how combining the fiber optic data with the surface pressure, pumping rates and tracer logs in conjunction with a fracture simulation platform where a detailed geomechanical and subsurface characterization data is incorporated to get a more accurate description of fracture geometry.

Implementation of planar 3D hydraulic fracture model in rock with layered compressive stress

Plane 3D model of hydraulic fracture propagation is implemented. Fluid flow inside the fracture, leak-of, rock deformation and breaking are taken into account. Asymptotic solution for tip of semi-infinite plane fracture is used to set boundary conditions for fluid flow problem and to calculate fracture front propagation velocity. Elastic and fluid flow equations are united in one system of nonlinear equations and solved simultaneously by Newton method with analytically calculated Jacoby matrix. The implemented model may be used as a start point for testing various methods of solution of “hydrodynamic-elasticity” problem and improving their convergence speed. Also model can be used for developed hydraulic fracture simulation.

Benchmark Analysis of Ductile Fracture Simulation for Circumferentially Cracked Pipes Subjected to Bending

To predict fracture behavior for ductile materials, some ductile fracture simulation methods different from classical approaches have been investigated based on appropriate models of ductile fracture. For the future use of the methods to overcome restrictions of classical approaches, the applicability to the actual components is of concern. In this study, two benchmark problems on the fracture tests supposing actual components were provided to investigate prediction ability of simulation methods containing parameter decisions. One was the circumferentially through-wall and surface cracked pipes subjected to monotonic bending, and the other was the circumferentially through-wall cracked pipes subjected to cyclic bending. Participants predicted the ductile crack propagation behavior by their own approaches, including FEM employed GTN yielding function with void ratio criterion, are FEM employed GTN yielding function, FEM with fracture strain or energy criterion modified by stress triaxiality, XFEM with J or ?J criterion, FEM with stress triaxiality and plastic strain based ductile crack propagation using FEM, and elastic-plastic peridynamics. Both the deformation and the crack propagation behaviors for monotonic bending were well reproduced, while few participants reproduced those for cyclic bending. To reproduce pipe deformation and fracture behaviors, most of groups needed parameters which were determined to reproduce pipe deformation and fracture behaviors in benchmark problems themselves and it is still difficult to reproduce them by using parameters only from basic materials tests.

Optimization Approach for Determination of the Dosage of Diversion Agents in Temporarily Plugging Fracturing of Shale Using 3D Printing Fractures

Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to the simulated fracture in Temco fracture conductivity system to mimic the practical treatment of temporarily plugging fracturing. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70o could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.

Advanced Fracturing Design Simulator-Assisted Modeling Coupled with Application of Enhanced Stimulation Fluids Raises Performance of Acid Fractured Wells

Important factors affecting acid fracturing efficiency include etched fracture geometry, cleanup, and optimum differential etching to retain open channels after fracture closure. A recently applied integrated approach combined improvements in all three factors: new fracture simulation techniques enabled fracture geometry optimization, single-phase retarded acid provided significant increase in half-length, and high retained permeability viscous fluids supported better fracture cleanup. The approach was successfully implemented in several carbonate oil fields and resulted in a substantial productivity index increase. The approach enables acid fracture optimization in three steps. First, the high retained permeability, low-pH pad fluids and polymer-free leakoff control acids are used in combination to enhance formation cleanup after a treatment and to reduce the concentration of polymers in fissures network of naturally fractured carbonate reservoirs. Second, a new single-phase retarded acid is used to achieve longer half-length due to retarded reaction with formation rock and favorable viscous fingering effects. Third, a new acid fracturing simulation model is used to optimize fracture geometry. The simulation technique employs an innovative transport model that includes the viscous fingering effect, advanced leakoff simulation, changing acid rheology upon spending, and a novel calculation approach to mixed fluids' rheology. This combined concept was applied during acid fracturing treatments in moderate permeability wells of carbonate reservoirs with target intervals up to 4,600 m TVD and temperatures up to 125°C. The treatments consisted of guar-free low-pH pad fluid, polymer-free leakoff control acid, and single-phase retarded acid. Treatment optimization was performed using an advanced acid fracturing simulator to properly address the transport processes within the fracture in a low-stress-contrast environment. After the treatments, the pressure transient analysis indicated a strong linear regime for more than 15 hours, indicating effective fracture half-length at least 25% higher than average half-length after acid fracturing in offset wells where the conventional approach had been applied. Post-treatment half-length calculations showed a good match with advanced simulator results and proved the importance of accounting for viscous fingering effects during acid fracture half-length calculations. Calculation of the productivity index from the production data showed at least 15% increase compared to conventional acid fracturing treatments. The post-fracturing production decline rate was at least 20% slower than that of the conventional treatment in offset wells, which can be explained by the longer conductive fracture.

A Novel Design Method for Optimizing the Diverter Dosage in Hydraulic Fracturing Using Three-Dimensionally Printed Fractures

Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.