Some lessons learnt from drilling a shale gas well in Western Australia

2014 ◽  
Vol 54 (1) ◽  
pp. 15
Author(s):  
Vamegh Rasouli
Keyword(s):  
Mechanical Properties ◽  
Shale Gas ◽  
Gas Flow ◽  
Joint Venture ◽  
Gas Well ◽  
Eastern Area ◽  
Well Design ◽  
Surface Location ◽  
Coal Measures ◽  
Exploration Well

The Arrowsmith–2 well is the first dedicated shale gas well in WA. The well is situated in the central eastern area of Permit EP413, with the surface location being about 30 km north of the township of Eneabba. Norwest, as the operator and on behalf of its joint venture partners, drilled the Arrowsmith–2 exploration well in mid-2011. In 2012 the well was subsequently perforated and fracture stimulated in five discrete stages across four formations: the High Cliff Sand Stone (HCSS); Irwin River Coal Measures (IRCM); Carynginia Formation; and, Kockatea Shale. The fraccing results have shown excellent rates of gas flow for the size of the intervals fracced, and have produced oil and/or condensate to surface from the two intervals flowed back. This paper discusses some drilling operation and design aspects of Arrowsmith–2. A review of the regional geology, basic well design, and well objectives will be given. The importance of geomechanical studies for minimising wellbore-related problems during drilling and after that for hydraulic fracturing operation will be discussed, and the results of the studies undertaken presented. The wireline logging suite run in this well was used to interpret the formations’ mechanical properties. Also, laboratory tests were performed to estimate hydro-mechanical properties of the formations. The lessons from drilling this well will be used for drilling future wells in the area with the objective of saving time and costs.

scholarly journals Prediction of Production Performance of Refractured Shale Gas Well considering Coupled Multiscale Gas Flow and Geomechanics

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-21 ◽  
Author(s):  
Zhiqiang Li ◽  
Zhilin Qi ◽  
Wende Yan ◽  
Zuping Xiang ◽  
Xiang Ao ◽  
...  
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Knudsen Diffusion ◽  
Stress Sensitivity ◽  
Production Performance ◽  
Design Parameters ◽  
Production Loss ◽  
Apparent Permeability ◽  
Gas Well ◽  
The Matrix

Production simulation is an important method to evaluate the stimulation effect of refracturing. Therefore, a production simulation model based on coupled fluid flow and geomechanics in triple continuum including kerogen, an inorganic matrix, and a fracture network is proposed considering the multiscale flow characteristics of shale gas, the induced stress of fracture opening, and the pore elastic effect. The complex transport mechanisms due to multiple physics, including gas adsorption/desorption, slip flow, Knudsen diffusion, surface diffusion, stress sensitivity, and adsorption layer are fully considered in this model. The apparent permeability is used to describe the multiple physics occurring in the matrix. The model is validated using actual production data of a horizontal shale gas well and applied to predict the production and production increase percentage (PIP) after refracturing. A sensitivity analysis is performed to study the effects of the refracturing pattern, fracture conductivity, width of stimulated reservoir volume (SRV), SRV length of new and initial fractures, and refracturing time on production and the PIP. In addition, the effects of multiple physics on the matrix permeability and production, and the geomechanical effects of matrix and fracture on production are also studied. The research shows that the refracturing design parameters have an important influence on the PIP. The geomechanical effect is an important cause of production loss, while slippage and diffusion effects in matrix can offset the production loss.

Exergy, Energy, and Gas Flow Analysis of Hydrofractured Shale Gas Extraction

2016 ◽  
Vol 138 (6) ◽  
Author(s):  
Noam Lior
Keyword(s):  
Shale Gas ◽  
Energy Demand ◽  
Gas Flow ◽  
Exergy Analysis ◽  
System Analysis ◽  
Embodied Energy ◽  
Gas Well ◽  
The Matrix ◽  
Small Flow ◽  
Exergy Consumption

The objectives of this study are to (a) evaluate the exergy and energy demand for constructing a hydrofractured shale gas well and determine its typical exergy and energy returns on investment (ExROI and EROI), and (b) compute the gas flow and intrinsic exergy analysis in the shale gas matrix and created fractures. An exergy system analysis of construction of a typical U.S. shale gas well, which includes the processes and materials exergies (embodied exergy) for drilling, casing and cementing, and hydrofracturing (“fracking”), was conducted. A gas flow and intrinsic exergy numerical simulation and analysis in a gas-containing hydrofractured shale reservoir with its formed fractures was then performed, resulting in the time- and two-dimensional (2D) space-dependent pressure, velocity, and exergy loss fields in the matrix and fractures. The key results of the system analysis show that the total exergy consumption for constructing the typical hydrofractured shale gas well is 35.8 TJ, 49% of which is used for all the drilling needed for the well and casings and further 48% are used for the hydrofracturing. The embodied exergy of all construction materials is about 9.8% of the total exergy consumption. The ExROI for the typical range of shale gas wells in the U.S. was found to be 7.3–87.8. The embodied energy of manufactured materials is significantly larger than their exergy, so the total energy consumption is about 8% higher than the exergy consumption. The intrinsic exergy analysis showed, as expected, very slow (order of 10−9 m/s) gas flow velocities through the matrix, and consequently very small flow exergy losses. It clearly points to the desirability of exploring fracking methods that increase the number and length of effective fractures, and they increase well productivity with a relatively small flow exergy penalty.

A Simulation Software of Critical Sour Well Blowout Based on FLUENT

2011 ◽  
Vol 383-390 ◽  
pp. 5130-5135
Author(s):  
Qing Chun Ma ◽  
Lai Bin Zhang
Keyword(s):  
Emergency Response ◽  
Gas Flow ◽  
Flow Direction ◽  
Simulation Software ◽  
Industrial Safety ◽  
Gas Well ◽  
Well Design ◽  
Design Structure ◽  
Safety Plan ◽  
Sour Gas

Well site safety plan, which included well design, emergencyresponse plan (ERP) etc, is the key prerequisite for drilling the critical sour gas well. A right emergency response zone (EPZ) is quite difficult to make sure on the site, because that it affected by release rate of H2S, gas composition, the well site surrounding topography, and other specific circumstances. To solve this problem, A blowout simulation software based on FLUENT be developed, which could predict affected areas when the critical sour blowout, the gas flow direction, and the H2S concentration distribution. On this basis, the safety layout surrounding the well site can be planned. The article provides the design structure and main functions of the software. The software can provide the theoretical basis of industrial safety.

THE RENEWED SEARCH FOR OIL AND GAS IN THE BASS BASIN: RESULTS OF YOLLA-2 AND WHITE IBIS-I

1999 ◽  
Vol 39 (1) ◽  
pp. 248 ◽  
Author(s):  
R.G. Lennon ◽  
R.J. Suttill ◽  
D.A. Guthrie ◽  
A.R. Waldron
Keyword(s):  
Joint Venture ◽  
Oil And Gas ◽  
Oil Accumulation ◽  
Field Development ◽  
Seismic Control ◽  
White Ibis ◽  
Basement High ◽  
Oil Rim ◽  
Coal Measures ◽  
Exploration Well

Boral Energy Resources Ltd and its Joint Venture partners drilled two weUs in the offshore Bass Basin during 1998. Both wells targetted reservoirs in the Upper Cretaceous to Eocene Eastern View Coal Measures (EVCM).Yolla–2, located in Petroleum Licence T/RL1, appraised sandstones within the EVCM, first established gas bearing in the Yolla structure by the 1985 exploration well Yolla–1, drilled by Amoco. The exploration well White Ibis–1, located in adjacent permit T/18P, was a crestal test on a large basement high updip of the 1967 well Bass-3, drilled by Esso.Both wells of the 1998 drilling program encountered gas columns in the objective Paleocene to Lower Eocene section of the EVCM (Intra-EVCM). Liquids-rich gas was recovered from these reservoirs in wireline tests. Formation pressure data suggest a thin oil rim is developed in White Ibis–1. Neither well was tested in cased hole though White Ibis–1 was suspended for potential re-entry. Yolla–1 also encountered a gas and oil accumulation at the top of the Eastern View Coal Measures, but this level was not an objective in Yolla–2.Based on well results and 3D seismic control, a gas resource of between 450–600 BCF OGIP is currently estimated in the Yolla Field. The gas accumulation encountered in White Ibis–1 is estimated at 85 BCF OGIP.The 1998 drilling campaign has provided encour-agement to the T/RL1 and T/18P Joint Ventures to continue the search for both oil and gas in the Bass Basin. Markets for gas are being pursued in both Tasmania and Victoria and engineering studies are being undertaken in parallel to refine parameters for a potential Yolla Field development. The White Ibis Field may provide a candidate as a satellite to such a development. Depending on the outcomes of these studies, further drilling may occur in 1999 to increase confidence in the reserves base in the Yolla Field, and to further evaluate the exploration potential of T/18P.

Economic benefit of shale gas exploitation based on back propagation neural network

2020 ◽  
Vol 39 (6) ◽  
pp. 8823-8830
Author(s):  
Jiafeng Li ◽  
Hui Hu ◽  
Xiang Li ◽  
Qian Jin ◽  
Tianhao Huang
Keyword(s):  
Neural Network ◽  
Shale Gas ◽  
Bp Neural Network ◽  
Large Scale ◽  
Linear Prediction ◽  
Back Propagation ◽  
Back Propagation Neural Network ◽  
Economic Benefits ◽  
Gas Well ◽  
Well Production

Under the influence of COVID-19, the economic benefits of shale gas development are greatly affected. With the large-scale development and utilization of shale gas in China, it is increasingly important to assess the economic impact of shale gas development. Therefore, this paper proposes a method for predicting the production of shale gas reservoirs, and uses back propagation (BP) neural network to nonlinearly fit reservoir reconstruction data to obtain shale gas well production forecasting models. Experiments show that compared with the traditional BP neural network, the proposed method can effectively improve the accuracy and stability of the prediction. There is a nonlinear correlation between reservoir reconstruction data and gas well production, which does not apply to traditional linear prediction methods

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