An Improved Model for Predicting Heat Losses and Pressure Changes in Steam Injection Wells—Part 2: Model Evaluation

1987 ◽  
Vol 109 (4) ◽  
pp. 225-229 ◽  
Author(s):  
S. C. Yao ◽  
N. D. Sylvester
Keyword(s):  
Solution Method ◽  
Steam Injection ◽  
Heat Losses ◽  
Steam Quality ◽  
Injection Wells ◽  
Improved Model ◽  
Pressure Changes ◽  
Bottomhole Pressure ◽  
Common Field ◽  
Good Agreement

The improved model developed in Part 1 for predicting heat losses and pressure changes in steam injection wells is evaluated. It shows good agreement with limited field data. The improved model is used to predict the effects of steam injection time, rate and pressure, well depth and tubing diameter on heat losses, bottomhole pressure and downhole steam quality. A design example is presented to illustrate the solution method for a common field operations problem.

An Improved Model for Predicting Heat Losses and Pressure Changes in Steam Injection Wells—Part 1: Model Development

1987 ◽  
Vol 109 (4) ◽  
pp. 218-224 ◽  
Author(s):  
S. C. Yao ◽  
N. D. Sylvester
Keyword(s):  
Model Development ◽  
Pressure Change ◽  
Steam Injection ◽  
Heat Losses ◽  
Injection Wells ◽  
Two Phase ◽  
Runge Kutta Method ◽  
Flow Pressure ◽  
Improved Model ◽  
Pressure Changes

An improved model for predicting heat losses and pressure changes in steam injection wells is presented. The model incorporates a new two-phase, annular-mist flow pressure change model with heat transfer to the surroundings during wet steam injection. The model requires an iterative procedure which is solved numerically using a fourth-order Runge-Kutta method.

Wellbore Heat Losses In Deep Steam Injection Wells S1-B Zone, Cat Canyon Field

1978 ◽  
Author(s):  
J.O. Herrera ◽  
W.D. George ◽  
B.F. Birdwell ◽  
E.J. Hanzlik
Keyword(s):  
Steam Injection ◽  
Heat Losses ◽  
Injection Wells

Prediction of thermophysical properties of saturated steam and wellbore heat losses in concentric dual-tubing steam injection wells

Energy ◽  
2014 ◽  
Vol 75 ◽  
pp. 419-429 ◽  
Author(s):  
Hao Gu ◽  
Linsong Cheng ◽  
Shijun Huang ◽  
Baojian Du ◽  
Changhao Hu
Keyword(s):  
Thermophysical Properties ◽  
Steam Injection ◽  
Heat Losses ◽  
Saturated Steam ◽  
Injection Wells

Performance and Water Consumption of the Solar Steam-Injection Gas Turbine Cycle

2012 ◽  
Vol 135 (1) ◽  
Author(s):  
Maya Livshits ◽  
Abraham Kribus
Keyword(s):  
Gas Turbine ◽  
Water Consumption ◽  
Power Plants ◽  
Solar Power ◽  
Low Cost ◽  
Steam Injection ◽  
Water Recovery ◽  
Solar Power Plants ◽  
Improved Model ◽  
Hybrid Cycle

Solar heat at moderate temperatures around 200 °C can be utilized for augmentation of conventional steam-injection gas turbine power plants. Solar concentrating collectors for such an application can be simpler and less expensive than collectors used for current solar power plants. We perform a thermodynamic analysis of this hybrid cycle, focusing on improved modeling of the combustor and the water recovery condenser. The cycle's water consumption is derived and compared to other power plant technologies. The analysis shows that the performance of the hybrid cycle under the improved model is similar to the results of the previous simplified analysis. The water consumption of the cycle is negative due to water production by combustion, in contrast to other solar power plants that have positive water consumption. The size of the needed condenser is large, and a very low-cost condenser technology is required to make water recovery in the solar STIG cycle technically and economically feasible.

Toward Controllable Infill Completions Using Frac-Driven Interactions FDI Data

2021 ◽  
Author(s):  
Yuzhe Cai ◽  
Arash Dahi Taleghani
Keyword(s):  
Pressure Fluctuations ◽  
Pressure Response ◽  
Sudden Increase ◽  
Short Period ◽  
Coupled Geomechanics ◽  
Multi Phase ◽  
Shale Oil Reservoirs ◽  
Pressure Changes ◽  
Observation Wells ◽  
Bottomhole Pressure

Abstract Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.

Revisiting the Classical Experiment in Earthquake Control at the Rangely Oil Field, Colorado, 1970, Using a Coupled Flow and Geomechanical Model

2021 ◽  
Author(s):  
Josimar A. Silva ◽  
Hannah Byrne ◽  
Andreas Plesch ◽  
John H. Shaw ◽  
Ruben Juanes
Keyword(s):  
Pore Pressure ◽  
Oil Field ◽  
Coupled Flow ◽  
Injection Wells ◽  
Rock Types ◽  
Pressure Diffusion ◽  
Main Fault ◽  
Injection Interval ◽  
Using Data ◽  
Pressure Changes

ABSTRACT The injection experiment conducted at the Rangely oil field, Colorado, was a pioneering study that showed qualitatively the correlation between reservoir pressure increases and earthquake occurrence. Here, we revisit this field experiment using a mechanistic approach to investigate why and how the earthquakes occurred. Using data collected from decades of field operations, we build a geological model for the Rangely oil field, perform reservoir simulation to history match pore-pressure variations during the experiment, and perform geomechanical simulations to obtain stresses at the main fault, where the earthquakes were sourced. As a viable model, we hypothesize that pressure diffusion occurred through a system of highly permeable fractures, adjacent to the main fault in the field, connecting the injection wells to the area outside of the injection interval where intense seismic activity occurred. We also find that the main fault in the field is characterized by a friction coefficient μ  ≈  0.7—a value that is in good agreement with the classical laboratory estimates conducted by Byerlee for a variety of rock types. Finally, our modeling results suggest that earthquakes outside of the injection interval were released tectonic stresses and thus should be classified as triggered, whereas earthquakes inside the injection interval were driven mostly by anthropogenic pore-pressure changes and thus should be classified as induced.

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