Diagnostic Fracture Injection Test Analysis Method Addresses Layered Rocks

2021 ◽  
Vol 73 (02) ◽  
pp. 54-55
Author(s):  
Chris Carpenter
Keyword(s):  
Hydraulic Fracturing ◽  
Flow Model ◽  
High Stress ◽  
Model Description ◽  
Base Case ◽  
Test Analysis ◽  
Fracture Width ◽  
Injection Test ◽  
Stress Region ◽  
Reservoir Simulator

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199690, “Diagnostic Fracture Injection Test Analysis and Interpretation in Layered Rocks,” by Shuang Zheng, SPE, Ripudaman Manchanda, SPE, and HanYi Wang, The University of Texas at Austin, et al., prepared for the 2020 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 4-6 February. The paper has not been peer reviewed. Formation-property estimations based on diagnostic fracture injection tests (DFITs) typically are based on analysis of pressure data assuming the closure of simple planar fractures in homogeneous reservoirs. These interpretations are incorrect when dealing with complex reservoir environments such as layered reservoirs with different properties and stresses. The complete paper investigates the effect of such complex environments on DFIT interpretation and presents a systematic method to analyze the data. Model Description A fully integrated hydraulic fracturing and reservoir simulator is used in this paper to simulate a DFIT. This simulator has been developed for designing and evaluating pad-scale fracturing treatments. It was then extended from a single-phase flow model to a multiphase black-oil-flow model and from a single-well fracturing simulator to an integrated fracturing and reservoir simulator. An energy-balance model was incorporated into the simulator to consider temperature changes. The fully implicit geomechanical hydraulic fracturing simulator was also extended to an integrated equation-of-state-based compositional fracturing and reservoir simulator in recent work. This simulator, which has been used in the literature and is discussed in detail in the complete paper, couples the reservoir fracture/wellbore system and has the capability to simulate the life cycle of wells: hydraulic fracturing, shut-in, flowback, primary production, and improved oil recovery. Base Case In the base case, a small amount of fluid is injected into the wellbore and the well is shut in for 10 days to mimic a DFIT job. The simulation domain is 400×400 m2 in the horizontal plane and 200 m in the height direction. The perforation clusters are placed in the middle of the domain. The bottomhole pressure vs. time is computed and plotted in this simulation. The simulation involves propagation of a single vertical fracture from a horizontal wellbore drilled in a formation with layered stress heterogeneity. The fracture maintains the largest width in the middle low-stress region, and the two low-stress regions below and above the middle low-stress region also have a large width compared with the fracture-tip regions and the high-stress regions. During fracture closure, fracture width decreases; however, the fracture width in the low-stress region is always higher than in the high-stress region. Results and Discussion The authors applied the numerical DFIT model to study the effect of different layer properties on DFIT signature and its interpretation. The simulation results indicate that most of the layer proper-ties have a major effect on DFIT signature and interpretation.

Work Flow History Matches Numerical Simulation Models of Fractured Shale Wells

2021 ◽  
Vol 73 (04) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Numerical Simulation ◽  
Fracture Toughness ◽  
Hydraulic Fracturing ◽  
History Matching ◽  
Simulation Models ◽  
Work Flow ◽  
Fracture Length ◽  
Matching Process ◽  
Rate Transient Analysis ◽  
Reservoir Simulator

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17–19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction The concept of rate transient analysis (RTA) involves the use of rate and pressure trends of producing wells to estimate properties such as permeability and fracture surface area. While very useful, RTA is an analytical technique and has commensurate limitations. In the complete paper, different RTA motifs are generated using a simulator. Insights from these motif simulations are used to modify simulation parameters to expediate and inform the history- matching process. The simulation history-matching work flow presented includes the following steps: 1 - Set up a simulation model with geologic properties, wellbore and completion designs, and fracturing and production schedules 2 - Run an initial model 3 - Tune the fracture geometries (height and length) to heuristic data: microseismic, frac-hit data, distributed acoustic sensing, or other diagnostics 4 - Match instantaneous shut-in pressure (ISIP) and wellhead pressure (WHP) during injection 5 - Make RTA plots of the real and simulated production data 6 - Use the motifs presented in the paper to identify possible production mechanisms in the real data 7 - Adjust history-matching parameters in the simulation model based on the intuition gained from RTA of the real data 8 -Iterate Steps 5 through 7 to obtain a match in RTA trends 9 - Modify relative permeabilities as necessary to obtain correct oil, water, and gas proportions In this study, the authors used a commercial simulator that fully integrates hydraulic fracturing, wellbore, and reservoir simulation into a single modeling code. Matching Fracturing Data The complete paper focuses on matching production data, assisted by RTA, not specifically on the matching of fracturing data such as injection pressure and fracture geometry (Steps 3 and 4). Nevertheless, for completeness, these steps are very briefly summarized in this section. Effective fracture toughness is the most-important factor in determining fracture length. Field diagnostics suggest considerable variability in effective fracture toughness and fracture length. Typical half-lengths are between 500 and 2,000 ft. Laboratory-derived values of fracture toughness yield longer fractures (propagation of 2,000 ft or more from the wellbore). Significantly larger values of fracture toughness are needed to explain the shorter fracture length and higher net pressure values that are often observed. The authors use a scale- dependent fracture-toughness parameter to increase toughness as the fracture grows. This allows the simulator to match injection pressure data while simultaneously limiting fracture length. This scale-dependent toughness scaling parameter is the most-important parameter in determining fracture size.

scholarly journals An Estimation of Fracture Width of an Artificial Fracture made by Laboratory Hydraulic Fracturing Test.

1996 ◽  
Vol 112 (9) ◽  
pp. 631-637 ◽  
Author(s):  
Mitsugu YAMASHITA ◽  
Tsutomu YAMAGUCHI ◽  
Michio KURIYAGAWA
Keyword(s):  
Hydraulic Fracturing ◽  
Fracture Width ◽  
Artificial Fracture

The Crack Arrest Capability of 9-Percent Ni Steels (ASTM 553, Type 1) LNG Storage Tanks

1991 ◽  
Vol 113 (3) ◽  
pp. 380-384
Author(s):  
P. B. Crosley ◽  
E. J. Ripling
Keyword(s):  
Fracture Toughness ◽  
Residual Stress ◽  
High Stress ◽  
Crack Arrest ◽  
Storage Tanks ◽  
Membrane Stress ◽  
High Stress Region ◽  
Fast Running ◽  
Stress Region

Safety of structures can be assured, even if cracks initiate in localized regions of abnormally low toughness, and/or abnormally high stress (LT/HS), if the materials from which they are fabricated have a high enough crack arrest fracture toughness. When this requirement is met, fast-running cracks that initiate in LT/HS regions arrest when their tip encounters material having normal toughness and stresses. The work described in this paper was carried out to determine the crack arrest capability of LNG storage tanks by determining the longest LT/HS region in which a crack could initiate and still arrest when it leaves this region. The determination consisted of relating a fracture analysis with the measured full-thickness crack arrest fracture toughness of three 9-percent Ni plates which were reported in reference [1]. The calculations used a residual stress pattern, produced by welding, superimposed on a typical membrane stress. The residual stress was selected as an example of a localized high stress region. It was found that tanks built from the poorest of the three tested plates could arrest cracks about 3/4 m long, while tanks built from the two tougher plates could arrest cracks almost 2 m long.

scholarly journals OPTIMISATION OF HYDRAULIC FRACTURING DESIGN IN LOWER OLIGOCENE RESERVOIR, KINH NGU TRANG OILFIELD

2018 ◽  
Vol 18 (3) ◽  
pp. 323-337
Author(s):  
Nguyen Huu Truong
Keyword(s):  
Hydraulic Fracturing ◽  
Complex Structure ◽  
Power Requirement ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
The North ◽  
Fracture Closure ◽  
Average Water ◽  
White Tiger ◽  
Fracture Height

Kinh Ngu Trang oilfield is of the block 09-2/09 offshore Vietnam, which is located in the Cuu Long basin, the distance from that field to Port of Vung Tau is around 140 km and it is about 14 km from the north of Rang Dong oilfield of the block 15.2, and around 50 km from the east of White Tiger in the block 09.1. That block accounts for total area of 992 km2 with the average water depth of around 50 m to 70 m. The characteristic of Oligocene E reservoir is tight oil in sandstone, very complicated with complex structure. Therefore, the big challenges in this reservoir are the low permeability and the low porosity of around 0.2 md to less than 1 md and 1% to less than 13%, respectively, leading to very low fracture conductivity among the fractures. Through the Minifrac test for reservoir with reservoir depth from 3,501 mMD to 3,525 mMD, the total leak-off coefficient and fracture closure pressure were determined as 0.005 ft/min0.5 and 9,100 psi, respectively. To create new fracture dimensions, hydraulic fracturing stimulation has been used to stimulate this reservoir, including proppant selection and fluid selection, pump power requirement. In this article, the authors present optimisation of hydraulic fracturing design using unified fracture design, the results show that optimum fracture dimensions include fracture half-length, fracture width and fracture height of 216 m, 0.34 inches and 31 m, respectively when using proppant mass of 150,000 lbs of 20/40 ISP Carbolite Ceramic proppant.

Fitness for Service Evaluation of Ring Joint Groove Cracking

1999 ◽  
Vol 122 (1) ◽  
pp. 72-75
Author(s):  
R. G. Brown ◽  
G. M. Buchheim ◽  
D. A. Osage ◽  
J. L. Janelle
Keyword(s):  
Driving Force ◽  
High Stress ◽  
Service Evaluation ◽  
Small Sample ◽  
Crack Advance ◽  
Ring Groove ◽  
Stress Region ◽  
Fracture Assessment ◽  
Inherent Problem ◽  
Pressure Hydrogen

Cracking of ring joint style flanges has been a recurring problem in the petrochemical industry, particularly in high-pressure hydrogen processing vessels. The cracking of the ring joint groove region is an inherent problem with the design. The ring groove is subjected to high stresses from the wedging action of the gasket and the ring groove radii are not substantial enough to effectively reduce the stress concentrating effect. A fitness for service assessment was conducted for a hydrogen processing vessel containing cracks in the ring groove radius region of a ring joint style flange. The flange was forged 2-1/4Cr-1Mo material with a Type 347 SS overlay. Results of an elastic-plastic numerical fracture mechanics assessment showed that the driving force for crack propagation was high for a very localized region near the ring groove radius. However, the driving force decreased significantly for deeper cracks as the crack tip became removed from the very localized high stress region of the ring groove. The assessment also showed that the highest stresses occurred during the bolt-up operation. Metallurgical tests were performed on a small sample removed from the flange. The chemistry, grain size, microstructure, and hardness of the material indicated that the probability that this material had very low resistance to hydrogen-assisted crack growth during downtime was quite small and that the resistance to crack advance during service was good. Therefore, the combined results of the fracture assessment and metallurgical testing were used to justify continued operation without repair of the cracks present in the flange. [S0094-9930(00)01901-6]

Active monitoring of hydraulic fracture propagation: an experimental and numerical study

2011 ◽  
Vol 51 (1) ◽  
pp. 479 ◽  
Author(s):  
Amin Nabipour ◽  
Brian Evans ◽  
Mohammad Sarmadivaleh
Keyword(s):  
Hydraulic Fracturing ◽  
Real Time ◽  
Hydraulic Fracture ◽  
Numerical Study ◽  
Fluid Pressure ◽  
Active Monitoring ◽  
Fracture Width ◽  
True Triaxial ◽  
Transmitted Waves ◽  
Triaxial Cell

Hydraulic fracturing is known as one of the most common stimulation techniques performed in oil and gas wells for maximising hydrocarbon production. It is a complex procedure due to numerous influencing factors associated with it. As a result, hydraulic fracturing monitoring techniques are used to determine the real-time extent of the induced fracture and to prevent unwanted events. Although the well-known method of monitoring is the microseismic method, active monitoring of a hydraulic fracture has shown capable of providing useful information about the fracture properties in both laboratory conditions and field operations. In this study, the focus is on laboratory experiment of hydraulic fracturing using a true-triaxial cell capable of simulating field conditions required for hydraulic fracturing. By injecting high-pressure fluid, a hydraulic fracture was induced inside a 20 cm cube of cement. Using a pair of ultrasonic transducers, transmission data were recorded before and during the test. Both cases of an open and closed hydraulic fracture were investigated. Then, using a discrete particle scheme, seismic monitoring of the hydraulic fracture was numerically modelled for a hexagonally packed sample and compared with the lab results. The results show good agreements with data in the literature. As the hydraulic fracture crosses the transducers line, signal dispersion was observed in the compressional wave data. A decrease was observed in both the amplitude and velocity of the waves. This can be used as an indicator of the hydraulic fracture width. As the fracture closes by reducing fluid pressure, a sensible increase occurred in the amplitude of the transmitted waves while the travel time showed no detectable variations. The numerical model produced similar results. As the modelled hydraulic fracture reached the source-receiver line, both amplitude and velocity of the transmitted waves decreased. This provides hope for the future real-time ability to monitor the growth of induced fractures during the fraccing operation. At present, however, it still needs improvements to be calibrated with experimental results.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

2016 ◽  
Vol 56 (1) ◽  
pp. 225 ◽  
Author(s):  
Kunakorn Pokalai ◽  
David Kulikowski ◽  
Raymond L. Johnson ◽  
Manouchehr Haghighi ◽  
Dennis Cooke
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
High Stress ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Fracture Plane ◽  
Natural Fractures ◽  
Geomechanical Model ◽  
Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

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