Coal Seam Gas Wells Research Articles

Effects of non-Darcy flow on the performance of coal seam gas wells

Although it has been reported that the gas flow in the cleat system may be of the non-Darcy nature, little has been known on how this non-Darcy flow affects the coal seam gas (CSG) extraction. One of the major reasons is that prior studies on this subject have not included the impact of gas sorption-induced coal deformation (swelling or shrinking) and the nature of two extremely different time scales between processes in the coal matrix and ones in the cleat system. In this study, a fully coupled finite element (FE) model of coal deformation (gas sorption induced swelling or shrinking), non-Darcy flow in fractures and gas diffusion in coal matrix is developed to quantify these non-Darcy flow effects. The fully coupled model can include EDM (Equilibrium Desorption Model) or DDM (Dynamic Desorption Model). In EDM, the gas sorption in the matrix system is a function of gas pressure only, i.e., the sorption process completes instantly when the cleat pressure changes. In DDM, the gas sorption in the matrix system is a function of both gas pressure in the cleat and the diffusion time in the matrix, i.e., a time lag between the cleat flow and diffusion process in the matrix exists. When only Darcy flow is assumed, this model was verified against both the model results of a vertical gas well performance by using ECLIPSE and field data from the Horseshoe Canyon coalbed gas well. Both EDM and DDM are applied to quantify the relationship among non-Darcy effect, production parameters, diffusion times, and coal seam compaction. Model results indicate that the non-Darcy effect is significant for high pressure drops and exists only within a small region near wellbore and that different diffusion times may produce two peaks of production rate, one is due to gas flow in the cleat system at the early stage and the other is due to gas diffusion at the late stage. The coal seam compaction can reduce the production rate much more than the non-Darcy flow effect at the early stage but has slightly impact at the late stage.

Consequence Analysis of Scarcity using Impacts from Resource Substitution

Abstract Published data from Australian and international sources are used to compile inputs and outputs for the combined system of fuel extraction and processing and electricity generation, for the cases of conventional natural gas, coal seam gas, and black coal fuels. A new method is being developed to assess the consequences of resource scarcity using mid-point impact indicators derived from established life cycle assessment methodology. When one particular resource such as natural gas is substituted by another resource such as coal, then the difference between the indicators corresponds to the environmental impact associated with this substitution. In this study, these differences are compared for the substitution of conventional gas with either black coal or coal seam gas to generate electricity. The results indicate lower cradle to gate impacts in global warming, acidification, particulates and solid waste generation as well as water consumption when substituting natural gas with coal seam gas. Conversely, substitution of conventional gas with black coal will result in overall higher impacts in these categories. However, coal seam gas involves greater withdrawal of underground water than in the case of the other fuels; this water requires treatment, involving production of a potentially damaging saline effluent. Potential risks may also exist arising from the large number of on-shore coal seam gas wells required per megajoule of fuel.

2011 PESA industry review: exploration

A continuing high and stable oil price through the latter part of 2011, oscillating around US$120 in the case of Tapis Crude, underpinned a small increase in exploration in 2011 in Australia compared with 2010, although there were marked regional differences between the northwest and southeast parts of the country. Exploration continued to be focused on the northwest offshore seeking incremental reserve additions of conventional gas to support planned and proposed liquid natural gas (LNG) projects and although information is hard to confirm, in general this program appears to have been successful with a number of relatively smaller discoveries and at least one major find, Zola–1. In the Cooper Basin exploration activity resumed after almost being shut down by floods in 2010, although flooding continued to be a problem in 2011. In the South Australian part, 27 new field wildcat (NFW) wells were drilled in 2011 compared with 8 in 2010. The program was also marked by a high rate of success. The other current major area of activity, the Queensland coal seam gas (CSG) program was also affected by flooding early in 2011 with 524 coal seam gas (CSG) wells drilled this year, compared with 648 in 2010 and more than 900 in 2009. In many jurisdictions shale gas or shale oil wells are not reported separately and are included in conventional petroleum wells in this report. Exploration for geothermal resources continued at a relatively low level with only 10 wells drilled in Australia in 2011, the most active state was Victoria with five wells. Despite the increase in activity, preliminary indications are that total exploration expenditure in 2011 will be less than in 2010. It is interesting to note that while the exploration effort in terms of wells and seismic has not changed much in the last few years the total expenditure has steadily increased in part reflecting the movement into deeper water drilling.

2010 PESA industry review–exploration

An uncertain global economy, offset by strong commodity prices, provided the backdrop to a subdued yet solid level of exploration activity in 2010. The major loci of activity in the Australian oil and gas industry were the Exmouth Plateau, where exploration for conventional gas in support of LNG projects was the primary driver, and the Bowen/Surat Basin, where coal seam gas (CSG) for LNG was the main target. Onshore permit awards dominated new licensing in 2010, with 31 exploration permits awarded over an area of 190,000 km2. The majority of these permits are focused on unconventional gas exploration. Conversely only 14 exploration permits (30,000 km) were awarded offshore, all in northwest Australia. This historically low level can be related to an already extensive coverage of existing permits in the offshore petroleum provinces and delays in the announcement of acreage awards from the 2009(II) acreage release. Twenty-nine 2D seismic surveys were started in 2010, with three still active at the end of the year. Once completed, the 2010 surveys will total nearly 37,000 km of data, with 76% offshore. Twenty-one 3D seismic surveys commenced in 2010, with six still active at year end. The 2010 surveys will ultimately comprise approximately 29,000 km2 of data, with 95% offshore. Northwest Australia dominated seismic activities. Exploration drilling for conventional hydrocarbon resources was relatively subdued in 2010, with 63 wells spudded, compared to 92 wells in 2008 and 74 in 2009. Of the 49 wildcat wells where results are known, 51% reported hydrocarbon discoveries. This was a little less than the 57% in 2009 and up on the 39% in 2008. The discoveries were distributed across most of the traditional petroleum provinces. High levels of CSG drilling continued in 2010, exceeding 2008 activity but less than that of 2009. At least 648 CSG wells were spudded in 2010, mostly in the new heartland plays of the Bowen/Surat, Gunnedah and Clarence-Moreton basins. This compares with more than 600 CSG wells drilled in 2008 and more than 900 in 2009. The first dedicated Australian shale gas exploration drilling took place in 2010. Emerging shale plays in the Cooper and Perth basins were tested.

The changing face of Queensland's petroleum industry

The cycles and related changes in exploration targets identified in this study show the evolution of the Queensland petroleum industry from conventional petroleum to coal seam gas dominance. Delineation of these cycles was undertaken using petroleum exploration well data, and production and reserves statistics. Although the cycles are defined on the basis of exploration activity, there is a very different history in the types of targets and commodities explored for in the Bowen-Surat and Cooper-Eromanga basins. Trends in exploration success have been influenced by technology improvements, better understanding of target reservoirs, proximity to infrastructure, government policy and world oil prices. Four distinct exploration cycles have been identified from the data. During the first cycle (1959–74) exploration focused predominantly on the shallower Jurassic-aged reservoirs in the Bowen-Surat basins resulting in the discovery of most of the major conventional oil and gas fields. The second cycle (1979–89) saw exploration begin in earnest in the Cooper-Eromanga basins and a switch to predominantly Triassic-aged reservoirs in the Bowen-Surat basins. The first coal seam gas exploration wells were drilled during this cycle. The third cycle (1990–99) shows a decrease in the number of conventional petroleum wells across both regions and the beginning of the switch to the present dominance of coal seam gas. The fourth cycle (2000–present) shows a significant decrease in the number of conventional exploration wells drilled across both regions, but an increase in the success rates. All conventional discoveries in the Bowen-Surat basins during cycle four have been in Permian-aged reservoirs, reflecting a change in the exploration focus to deeper parts of the Bowen Basin. Coal seam gas exploration has expanded significantly, with the Walloon Coal Measures being targeted, resulting in nearly four coal seam gas wells drilled for each conventional petroleum exploration well state-wide since 2000. Examination of coal seam gas exploration highlights the many false starts since the first well was drilled in 1980. Exploration has shifted from area to area as companies tested different exploration concepts and completion techniques. The most obvious shift has been from Permian-aged targets of the Bowen Basin into the Jurassic-aged Walloon Coal Measures in the Surat and Clarence-Moreton basins, as its prospectivity was realised.

Application of nuclear magnetic resonance measurements in the evaluation of two coal seam gas wells in the Pedirka Basin

In 2008, Central Petroleum was involved in an extended exploration campaign in the Pedirka Basin. The main targets were conventional oil and coal seam gas (CSG). A comprehensive logging program including nuclear magnetic resonance (NMR) measurements was acquired, with the scope of evaluating both targets in two wells. NMR tools measure the magnetisation of hydrogen protons present in the flushed-zone of the formation pore space. By calibrating this measurement in a water tank, NMR tools provide formation porosity independent of lithology, while classical methods for deriving porosity (density, neutron, etc.) are lithology dependent. While in conventional plays (clastics, carbonates) porosity is needed for evaluating the reservoir storage capacity, in coal beds porosity is needed for evaluating the surface areas of the pores. As methane in coal is bound to the coal surface, total pore surface affects the coal bed methane producing capacity. NMR measurements also provide information about porosity/grain size distribution, permeability and hydrocarbon saturation in conventional formations. This information can be very useful for evaluating coal seam gas, provided the conventional models can be converted and applied in coal beds. Evaluation of coal seam gas prospects using nuclear magnetic resonance is an industry first. This presentation highlights the benefits and difficulties of nuclear magnetic resonance evaluation of CSG prospects in these two wells.

Stochastic forecasting of production potential using customised type curves in coal seam gas

This paper discusses a new workflow to stochastically estimate the performance of future production in coal seam gas (CSG) developments. Usually performance evaluations for CSG wells are conducted using either much-generalised statistical methods or numerical simulation. Both approaches have significant drawbacks; the former methods are quick but very often lack accuracy, while the latter is very accurate however also usually highly complex in set-up and computation. The presented workflow is a new approach to well performance prediction that combines speed and reasonable accuracy. The workflow generates a set of key performance indicators of existing wells derived from historic dynamic data (water and gas production rates, pressures, etc.), static data (initial coal and reservoir properties, etc.) and predicted data (simplified production forecasts). The wells are then grouped according to the similarity of their KPIs. The production profiles of the wells within the same group are combined to a type curve that is described by the most likely production profile and an associated uncertainty range. A data-driven expert system is used to identify and capture the correlations of the parameters such as geographic locations, well spacing, reservoir properties and the group membership (equivalent to type curve). This expert system can then be applied to any location in the field in order to determine the most likely group membership of a potential well. The classification of a new well to a group is hereby not necessarily unique; the expert system might classify a new well into several groups and assign a probability of occurrence for each of the groups. A Monte Carlo routine is then applied to forecast the performance of the new well locations honoring the respective probability of occurrence of each type curve.