Offshore CRI Well Performance Diagnostics and Fractured Domain Mapping Using Injection Data Analytics and Hydraulic Fracturing Simulation, Verified Through 4D Seismic and Wireline Logging

2021 ◽  
Author(s):  
Franz Marketz ◽  
David Brown ◽  
Roman Alyabiev ◽  
Pavel Khudorozhkov ◽  
Oleg Sychov
Keyword(s):  
Waste Disposal ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Pressure Increase ◽  
Pressure Data ◽  
Injection Zone ◽  
Domain Mapping ◽  
Fracture Models ◽  
4D Seismic ◽  
Injection Pressures

Abstract The cuttings re-injection (CRI) well in the Astokh area of Piltun-Astokhskoye field offshore Sakhalin Russia is one of the longest operating drilling waste disposal wells in the oil and gas industry worldwide. The Astokh area has been developed as a waterflood and is operated by Sakhalin Energy, a joint venture between Gazprom, Shell, Mitsui, and Mitsubishi. The Astokh CRI well has been utilized for waste injection for over 16 years. About 300,000 m3 of waste has been disposed into the main injection zone of the CRI well. Monitoring and modelling the CRI process to understand the evolution of the disposal domain is paramount for safeguarding further disposal operations. The disposal domain can be described as a complex system of multiple hydraulic and natural fractures due to injection under fracturing conditions. CRI domain evaluation includes analysis of historical injection pressures to identify the reasons of continuous injection pressure increase with increasing cumulative waste volumes disposed, to confirm domain containment, and to predict remaining domain capacity. Transient pressure analysis has revealed that the fracture closure pressure, driven by pore pressure increase and the accumulation of injected solid-phase waste, is the key parameter affecting injection pressures. Injection intensity, periods of shut-in, large overflushes, and solids-free liquids injections with corresponding solids and stresses redistribution are the other factors that affecting the pressure trends. CRI domain mapping was carried out with history-matched time-lapse 3D hydraulic fracture models. Injection pressure history matching results reveal the fracture geometry evolution during well life. The distribution of the injected liquid phase in the sand layers was modeled with a 3D dynamic reservoir sector model, matched with injection pressures and with formation pressure data in two offset wells, located at a distance of 1 and 2 kilometers, respectively. A matched model was then used to assure fracture containment for future waste disposal and to estimate remaining domain capacity. High-precision temperature and spectral noise logs were acquired in seawater injection and shut-in modes. The log-derived fracture height confirmed the domain size predicted by the matched model. 4D seismic data processing revealed that dimensions of Geomechanically Altered Rock Volume (GARV) were also in the same range as predicted by the model p. The integration of CRI domain evaluation with matched 3D hydraulic fracture models, well logs and 4D seismic demonstrated that injection pressure data collected during every injection cycle may be sufficient to characterize disposal domain evolution and to estimate domain capacity.

Low-Cost Measurement of Hydraulic Fracture Dimensions Using Pressure Data in Treatment and Observation Wells – A Workflow for Every Well

2021 ◽  
Author(s):  
A. Kirby Nicholson ◽  
Robert C. Bachman ◽  
R. Yvonne Scherz ◽  
Robert V. Hawkes
Keyword(s):  
Hydraulic Fracturing ◽  
Real Time ◽  
Hydraulic Fracture ◽  
Full Scale ◽  
Pressure Data ◽  
Observation Well ◽  
High Quality ◽  
Fracture Length ◽  
Geometry Model ◽  
Observation Wells

Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.

A New Technique to Predict In Situ Stress Increment Due to Biowaste Slurry Injection Into a Sandstone Formation

2018 ◽  
Vol 140 (12) ◽  
Author(s):  
Sherif M. Kholy ◽  
Ahmed G. Almetwally ◽  
Ibrahim M. Mohamed ◽  
Mehdi Loloi ◽  
Ahmed Abou-Sayed ◽  
...  
Keyword(s):  
Function Analysis ◽  
Injection Pressure ◽  
In Situ Stress ◽  
New Technique ◽  
Strong Impact ◽  
Stress Increment ◽  
Injection Zone ◽  
Fracture Closure ◽  
Slurry Injection

Underground injection of slurry in cycles with shut-in periods allows fracture closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. However, in many cases, the accumulation of solids on the fracture faces slows down the leak off which can delay the fracture closure up to several days. The objective in this study is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow fracture closure. The new technique predicts the fracture closure pressure from the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical/mechanical properties including porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. Actual injection pressure data from a biosolids injector have been used to validate the new predictive technique. During the early well life, the match between the predicted fracture closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry injection and stress shadow analysis. Furthermore, the work shows that the injection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in situ stress equalizes the upper barrier stress.

A New Approach for Reliable Estimation of Hydraulic Fracture Properties Using Elliptical Flow Data in Tight Gas Wells

2009 ◽  
Vol 12 (02) ◽  
pp. 254-262 ◽  
Author(s):  
Yueming Cheng ◽  
W. John Lee ◽  
Duane A. McVay
Keyword(s):  
Hydraulic Fracture ◽  
Finite Conductivity ◽  
Tight Gas ◽  
Well Test ◽  
Pressure Data ◽  
Gas Wells ◽  
New Approach ◽  
Fracture Properties ◽  
Elliptical Flow ◽  
Half Length

Summary Gas wells in low-permeability formations usually require hydraulic fracturing to be commercially viable. Pressure transient analysis in hydraulically fractured tight gas wells is commonly based on analysis of three flow regimes: bilinear, linear, and pseudoradial. Without the presence of pseudoradial flow, neither reservoir permeability nor fracture half-length can be independently estimated. In practice, as pseudoradial flow is often absent, the resulting estimation is uncertain and unreliable. On the other hand, elliptical flow, which exists between linear flow and pseudoradial flow, is of long duration (typically months to years). We can acquire much rate and pressure data during this flow regime, but no practical well test analysis technique is currently available to interpret these data. This paper presents a new approach to reliably estimate reservoir and hydraulic fracture properties from analysis of pressure data obtained during the elliptical flow period. The method is applicable to estimate fracture half-length, formation permeability, and skin factor independently for both infinite- and finite-conductivity fractures. It is iterative and features rapid convergence. The method can estimate formation permeability when pseudoradial flow does not exist. Coupled with stable deconvolution technology, which converts variable production-rate and pressure measurements into an equivalent constant-rate pressure drawdown test, this method can provide fracture-property estimates from readily available, noisy production data. We present synthetic and field examples to illustrate the procedures and demonstrate the validity and applicability of the proposed approach.

Comparison of Hydraulic Fracture Models for Highly Elongated Fractures of Variable Height

1986 ◽  
Vol 108 (2) ◽  
pp. 107-115 ◽  
Author(s):  
I. D. Palmer ◽  
C. T. Luiskutty
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Reasonable Agreement ◽  
High Stress ◽  
Vertical Direction ◽  
Critical Examination ◽  
Wellbore Pressure ◽  
Fracture Models ◽  
Fracture Height ◽  
Stress Contrast

There is a pressing need to compare and evaluate hydraulic fracture models which are now being used by industry to predict variable fracture height. The fractures of concern here are vertical fractures which have a pronounced elongation in the direction of the payzone, i.e., there is a dominant one-dimensional fluid flow along the payzone direction. A summary is given of the modeling entailed in the basic ORU fracture model, which calculates fracture height as a function of distance from the wellbore in the case of a continuous sand bounded by zones of higher (but equal) minimum in-situ stress. The elastic parameters are assumed the same in each layer, and injected flow rates and fluid parameters are taken to be constant. Leak-off is included with spurt loss, as well as non-Newtonian flow. An advantage of the model is its small computer run time. Predictions for wellbore height and pressure from the ORU model are compared separately with the AMOCO and MIT pseudo-3D models. In one instance of high stress contrast the ORU wellbore pressure agrees fairly well with the AMOCO model, but the AMOCO wellbore height is greater by 32 percent. Comparison between the ORU and MIT models in two cases (also high stress contrast) indicates height disagreement at the wellbore by factors of 1.5–2.5 with the MIT model giving a lower height. Thus it appears there can be substantial discrepancies between all three models. Next we compare the ORU model results with six cases of elongated fractures from the TERRA-TEK fully-3D model. Although two of these cases are precluded due to anomolous discrepancies, the other four cases show reasonable agreement. We make a critical examination of assumptions that differ in all the models (e.g., the effective modulus-stiffness multiplier approximation in the AMOCO model, the effect of finite fluid flow in the vertical direction in the MIT model, and the effect of 2D flow and limited perforated height in the TERRA-TEK model). Suggestions are made for reconciling some of the discrepancies between the various models. For example, the ORU/AMOCO height discrepancy appears to be resolved; for other discrepancies we have no explanation. Our main conclusion is that the AMOCO, TERRA-TEK and ORU models for fracture height and bottomhole pressure are in reasonable agreement for highly elongated fractures. Despite the difficulties in understanding the different models, the comparisons herein are an encouraging first step towards normalizing these hydraulic fracture models.

scholarly journals Investigation of Puffing and Micro-Explosion of Water-in-Diesel Emulsion Spray Using Shadow Imaging

Energies ◽  
2018 ◽  
Vol 11 (9) ◽  
pp. 2281 ◽  
Author(s):  
Mhadi A. Ismael ◽  
Morgan Heikal ◽  
A. A. Aziz ◽  
Cyril Crua ◽  
Mohmmed El-Adawy ◽  
...  
Keyword(s):  
Droplet Size ◽  
High Speed ◽  
Elevated Temperatures ◽  
Injection Pressure ◽  
Image Processing Algorithm ◽  
Long Distance ◽  
Secondary Atomization ◽  
High Injection ◽  
Digital Microscope ◽  
Injection Pressures

Water-in-diesel emulsions potentially favor the occurrence of micro-explosions when exposed to elevated temperatures, thereby improving the mixing of fuels with the ambient gas. The distributions and sizes of both spray and dispersed water droplets have a significant effect on puffing and micro-explosion behavior. Although the injection pressure is likely to alter the properties of emulsions, this effect on the spray flow puffing and micro-explosion has not been reported. To investigate this, we injected a fuel spray using a microsyringe needle into a high-temperature environment to investigate the droplets’ behavior. Injection pressures were varied at 10% v/v water content, the samples were imaged using a digital microscope, and the dispersed droplet size distributions were extracted using a purpose-built image processing algorithm. A high-speed camera coupled with a long-distance microscope objective was then used to capture the emulsion spray droplets. Our measurements indicated that the secondary atomization was significantly affected by the injection pressure which reduced the dispersed droplet size and hence caused a delay in puffing. At high injection pressure (500, 1000, and 1500 bar), the water was evaporated during the spray and although there was not enough droplet residence time, puffing and micro-explosion were clearly observed. This study suggests that high injection pressures have a detrimental effect on the secondary atomization of water-in-diesel emulsions.

History Matching Using 4D Seismic and Pressure Data on the Norne Field

2005 ◽  
Author(s):  
M. Lygren ◽  
O. Husby ◽  
B. Osdal ◽  
Y. El Ouair ◽  
M. Springer
Keyword(s):  
History Matching ◽  
Pressure Data ◽  
4D Seismic

Monitoring horizontal well hydraulic stimulations and geomechanical deformation processes in the unconventional shales of the Midland Basin using fiber-based time-lapse VSPs, microseismic, and strain data

2019 ◽  
Vol 38 (2) ◽  
pp. 130-137 ◽  
Author(s):  
Robert Hull ◽  
Robert Meek ◽  
Hector Bello ◽  
Kevin Woller ◽  
Jed Wagner
Keyword(s):  
Fiber Optics ◽  
Hydraulic Fracture ◽  
Single Mode ◽  
Time Lapse ◽  
Seismic Profile ◽  
External Pressure ◽  
Single Mode Fiber ◽  
Accurate Estimation ◽  
Fracture Geometry ◽  
Fracture Models

A variety of methods are utilized in an instrumented vertical wellbore to invert for and estimate the heights and lateral extents of the hydraulic fracture treatment. Data were acquired with externally mounted dual- and single-mode fiber optics for measuring strain, acoustics, and temperature. In addition, external pressure gauges, internal conventional tiltmeters, and geophones were also utilized. This instrumented well was used multiple times to record a number of nearby offset horizontal hydraulic stimulations and to record a time-lapse vertical seismic profile. By using multiple data acquisition techniques, we obtained a more comprehensive and accurate estimation of the hydraulic fracture geometry and the dynamic processes taking place internal to the propagating fractures. Furthermore, these data could be used to calibrate fracture models and the fracture interaction with the surrounding unconventional reservoir.

scholarly journals Effect of Multiple Flow Pulses on Hydraulic Fracture Network Propagation in Naturally Fractured Volcanic Rock

Energies ◽  
2020 ◽  
Vol 13 (3) ◽  
pp. 633
Author(s):  
Guangzhi Yang ◽  
Shicheng Zhang ◽  
Jia Wang ◽  
Ning Li ◽  
Xinfang Ma ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Fracture Network ◽  
Injection Rate ◽  
Injection Method ◽  
Injection Scheme ◽  
Fracture Complexity ◽  
Naturally Fractured ◽  
Fluid Leak

Exploring engineering methods for increasing fracture network complexity is important for the development of unconventional oil and gas reservoirs. In this study, we conducted a series of fracturing experiments on naturally fractured volcanic samples. An injection method, multiple flow pulses, is proposed to increase fracture complexity. The results show that fluid leaked into the natural fracture network (NFN) when the injection rate was low (0.2 mL/min); hydraulic-fracture-dominant fracture geometry was created with an injection rate of 2 and 5 mL/min. Under the 2 mL/min-injection scheme with 3 pulses, the injection pressure during the intermittent stage was low (<5 MPa), resulting in a limited increase in fracture complexity. When the number of the flow pulses increased to 5, the pressure drop rate in the fourth and fifth intermittent stage significantly increased, indicating an increase in the aperture of natural fractures (NFs) and in the fluid leak-off effect. Under the 5 mL/min injection scheme containing 5 pulses, besides the enhanced fluid leak-off, a sharp injection pressure drop was observed, indicating the activation of NFs. The complexity and the aperture of the ultimate fracture network further increased. The injection method, multiple flow pulses, can be used to create complex fracture networks effectively.

scholarly journals A Study of Combustion Characteristics of Two Gasoline–Biodiesel Mixtures on RCEM Using Various Fuel Injection Pressures

Energies ◽  
2020 ◽  
Vol 13 (12) ◽  
pp. 3265
Author(s):  
Ardhika Setiawan ◽  
Bambang Wahono ◽  
Ocktaeck Lim
Keyword(s):  
Heat Release ◽  
Ignition Delay ◽  
Fuel Injection ◽  
Injection Pressure ◽  
Fuel Mixture ◽  
Injection Rate ◽  
Injection Duration ◽  
Late Start ◽  
Fuel Injection Rate ◽  
Injection Pressures

Experimental research was conducted on a rapid compression and expansion machine (RCEM) that has characteristics similar to a gasoline compression ignition (GCI) engine, using two gasoline–biodiesel (GB) blends—10% and 20% volume—with fuel injection pressures varying from 800 to 1400 bar. Biodiesel content lower than GB10 will result in misfires at fuel injection pressures of 800 bar and 1000 bar due to long ignition delays; this is why GB10 was the lowest biodiesel blend used in this experiment. The engine compression ratio was set at 16, with 1000 µs of injection duration and 12.5 degree before top dead center (BTDC). The results show that the GB20 had a shorter ignition delay than the GB10, and that increasing the injection pressure expedited the autoignition. The rate of heat release for both fuel mixes increased with increasing fuel injection pressure, although there was a degradation of heat release rate for the GB20 at the 1400-bar fuel injection rate due to retarded in-cylinder peak pressure at 0.24 degree BTDC. As the ignition delay decreased, the brake thermal efficiency (BTE) decreased and the fuel consumption increased due to the lack of air–fuel mixture homogeneity caused by the short ignition delay. At the fuel injection rate of 800 bar, the GB10 showed the worst efficiency due to the late start of combustion at 3.5 degree after top dead center (ATDC).

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