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Kuznetsov D.,Arrow Energy | Cotterill S.,Tullow Oil | Giddins M.A.,Schlumberger | Blunt M.J.,Imperial College London
Society of Petroleum Engineers - SPE Asia Pacific Enhanced Oil Recovery Conference, EORC 2015 | Year: 2015

This paper describes a simulation study of the low-salinity effect in sandstone reservoirs. The proposed mechanistic model allows differentiation of water composition effects and includes multi-ionic exchange and double layer expansion. The manifestation of these effects can be observed in coreflood experiments. We define a set of chemical reactions, to describe the contribution of van der Waals forces, ligand exchange, and cation bridging to mobilization of residual oil. The reaction set is simplified by incorporating wettability weighting coefficients that reflect the contribution of different adsorbed ions to the wettability of the rock. Changes in wettability are accounted for by interpolation of the relative permeability and capillary pressure curves between the low and high salinity sets. We also construct and test simplified phenomenological models, one relating the change of the relative permeability to the concentration of a dissolved salinity tracer and another one to the concentration of a single adsorbed tracer. The full mechanistic model, with multiple ion tracking, is in good qualitative agreement with experimental data reported in the literature. A very close agreement with the mechanistic model was obtained for a coreflood simulation using single tracer phenomenological models. The similarity of the results is explained by the fact that the most critical factor influencing the flow behavior was the function used to interpolate between the oil- and water-wet sets of saturation curves. Similar interpolation functions in different models lead to similar oil recovery predictions. This study has developed a detailed chemical reaction model that captures both multicomponent ion exchange and double layer expansion effects, and can be used to improve understanding of low-salinity recovery mechanisms by analyzing their relative contributions. The approach of matching a tracer model to a detailed mechanistic model promises a route to the development of simplified, less computationally demanding proxy models for full field simulation studies. Copyright 2015, Society of Petroleum Engineers.

News Article | November 30, 2016

Under the purview of energy, coal bed methane primarily refers to the natural gas or methane recovery from un-mined coal seams and adjacent sandstones. Such methane recovery usually occurs prior to mining, whereas in some cases, coal seams remain un-mined and methane recovery from such sites is known as virgin coal bed methane. Coal bed methane recovery from un-mined coal mines is of strategic importance as absolute or maximum drainage of the methane seam is necessary to avoid the risk of explosion as well as mitigate the emission of methane in the atmosphere from coal mining operations. From the estimated global coal bed methane reserve of about 4,000 Tcf to 5,000 Tcf, about 20% to 25% is recoverable. The fact that the coal in some sites is at a greater depth, makes it not feasible to extract it on account of the associated safety. This and other environmental and economic considerations serve as the drivers for the global coal bed methane market. Further, the shifting focus towards the use of unconventional energy sources serves as another factor for the growth of global coal bed methane market.  The constraints of the coal bed methane are dependent on the accessibility of coal seams. Major constraints of the global coal bed methane market include environmental, regulatory, technical and economic challenges.  Among these, environmental constraints include risk associated with greenhouse gas emission. The economical challenges associated with the global coal bed methane market are more prevalent in the early stages of the recovery, when large quantities of water are pumped in with minimal recovery of revenue producing gas. This dewatering and produced water disposal cost is of significant importance for any carbon bed methane project. Although the development cost for the coal bed methane project is relatively lower, it is always a challenge to keep it within minimal range to achieve profitability. The technical constraints of the coal bed methane market depend on the well completion and optimization design to achieve maximum production with optimum number, spacing and location of wells. Also, handling and disposal of water at a minimal cost alongwith the efficient reservoir characterisation are other key technical restraints for global coal bed methane market.  Also, coal bed methane requires a low pressure pipeline system which acts as an economical constraint. However, the potential of carbon bed methane to serve as a supplement for conventional natural gas supply and its contribution towards the global energy mix will act as an opportunity for global coal bed methane market. However, the market expansion of the global coal bed methane will be dependent upon the growth of newer technology and development. Market segmentation of global coal bed methane can be done on the basis of application, technology and geography.  On the basis of application, the global carbon methane market includes commercial application, industrial application, power generation, residential application, and transportation. On the basis of technology, the global carbon bed methane market includes fracturing techniques including hydro-fracturing, proppant-based fracturing and chemical additive based fracturing, exploration, and drilling. Among these, fracturing techniques have been utilised most frequently for coal bed methane recovery.  On the basis of geography, the global coal bed methane market includes North America, Latin America, Asia Pacific, Japan, Western Europe, Eastern Europe, and Middle East & Africa. Among these, the largest carbon bed methane resource bases are found in Canada, China, US, Soviet Union and Australia, with Canada accounting for the maximum share followed by the Soviet Union, China, Australia and US. On a broader level, any country with abundant coal reserves and population, and high energy demand will serve as a potential market for carbon bed methane development at a global level.  The demand for coal bed methane gas is evident alongwith the demand for natural gas in China and other Asian countries. Associated exploration in the US has been active in the past few years whereas Canada witnessed lower exploration and the development offewer extraction technologies pertaining to global coal bed methane market. Some of the prominent players of the global coal bed methane market include Santos, Quick Silver Resources Inc, Baker Hughes Incorporated, BG Group, Arrow Energy, Blue Energy Limited, Halliburton, Dart Energy Ltd., Fortune Oil PLC, ConocoPhillips and Metgasco Limited. The research report presents a comprehensive assessment of the market and contains thoughtful insights, facts, historical data, and statistically supported and industry-validated market data. It also contains projections using a suitable set of assumptions and methodologies. The research report provides analysis and information according to categories such as market segments, geographies, types, technology and applications.

Jin H.,Indiana University | Schimmelmann A.,Indiana University | Mastalerz M.,Indiana University | Pope J.,CRL Energy Ltd. | And 3 more authors.
International Journal of Coal Geology | Year: 2010

Desorption canisters are routinely employed to quantify coalbed gas contents in coals. If purging with inert gas or water flooding is not used, entrapment of air with ~ 78.08 vol.% nitrogen (N2) in canisters during the loading of coal results in contamination by air and subsequent overestimates of N2 in desorbed coalbed gas. Pure coalbed gas does not contain any elemental oxygen (O2), whereas air contamination originally includes ~ 20.95 vol.% O2 and has a N2/O2 volume ratio of ~ 3.73. A correction for atmospheric N2 is often attempted by quantifying O2 in headspace gas and then proportionally subtracting atmospheric N2. However, this study shows that O2 is not a conservative proxy for air contamination in desorption canisters. Time-series of gas chromatographic (GC) compositional data from several desorption experiments using high volatile bituminous coals from the Illinois Basin and a New Zealand subbituminous coal document that atmospheric O2 was rapidly consumed, especially during the first 24 h. After about 2 weeks of desorption, the concentration of O2 declined to near or below GC detection limits. Irreversible loss of O2 in desorption canisters is caused by biological, chemical, and physical mechanisms. The use of O2 as a proxy for air contamination is justified only immediately after loading of desorption canisters, but such rapid measurements preclude meaningful assessment of coalbed gas concentrations. With increasing time and progressive loss of O2, the use of O2 content as a proxy for atmospheric N2 results in overestimates of N2 in desorbed coalbed gas. The indicated errors for nitrogen often range in hundreds of %. Such large analytical errors have a profound influence on market choices for CBM gas. An erroneously calculated N2 content in CBM would not meet specifications for most pipeline-quality gas. © 2009 Elsevier B.V. All rights reserved.

Johnson R.L.,Jr. | Mazumder S.,Arrow Energy
Society of Petroleum Engineers - International Petroleum Technology Conference 2014, IPTC 2014 - Innovation and Collaboration: Keys to Affordable Energy | Year: 2014

Coalbed methane (CBM) has been considered a relatively mature unconventional gas resource in North America. In Australia, where the CBM or coal seam gas (CSG) industry is nearly two decades old, there have been successful and unsuccessful pilot projects and resources have been slower to develop after nearly twenty-five years since North American technologies were exported internationally. Thus, it is reasonable to believe that there are differences outside North America that have hindered CBM development in Australia. Often CBM pilots owe their degree of success to one of three major factors: geologic or structural setting, reservoir properties, or completion strategies. Most pilot testing have been conducted either to characterize the production from a particular geo-domain associated with certain perceived geological risk and uncertainty or to estimate potential project reserves to a reasonable degree of accuracy. This need to reduce uncertainty is more pronounced in Australia based on the need to balance development decisions, tenure retention requirements, whilst minimising the risk for the upcoming development phase. Often in hindsight, the opportunity to increase the chance of success for good areas or reduce the expenditures in poor areas was achievable through improved reservoir characterisation or better pilot planning. In some cases, the resource volumes are large, but the progression of resources to reserves has been less certainty based on challenges. In this paper we will highlight some key observations from several Australian CSG pilots that led to success or challenges for each case. The authors' goals are to identify key indicators, which if recognised earlier may have increased the rate of success or reduced unnecessary expenditures in these pilot areas. Copyright © 2014, International Petroleum Technology Conference.

Connell L.D.,CSIRO | Mazumder S.,Arrow Energy | Sander R.,CSIRO | Camilleri M.,CSIRO | And 2 more authors.
Fuel | Year: 2016

This paper presents the results of a laboratory program of work to measure the coal properties required to apply models for the behaviour of the absolute reservoir permeability during gas production. These measurements were made on core samples from the Bowen Basin of Australia, an important area for coal seam methane production, and involved applying an integrated testing methodology. During the testing the pore pressure was increased in a stepwise fashion with gas adsorption equilibration allowed at each pressure step. The gas content of the intact sample was estimated from the gas taken up during equilibration and the sample swelling in response to adsorption measured. After adsorption had equilibrated, the geomechanical properties were determined through axial loading and measurement of the deformation and the permeability measured with respect to confining pressure. These permeability measurements were then used to estimate the cleat compressibility by fitting the Seidle model to the observations. The results from five coal samples are presented. A method is presented for the calculation of the cleat porosity, a difficult property to determine experimentally as it represents the proportion of the porosity involved in Darcy flow. Thus, the presented method uses a property determined from flow measurements; the cleat compressibility. The measured properties are used in the Shi-Durucan model to predict permeability behaviour with pressure drawdown. The results are compared to the field based estimates from the analysis of Mazumder et al. (2012). © 2015 Elsevier Ltd.

Langley C.,Arrow Energy | Spaander A.,Royal Dutch Shell
Society of Petroleum Engineers - International Petroleum Technology Conference 2013, IPTC 2013: Challenging Technology and Economic Limits to Meet the Global Energy Demand | Year: 2013

Arrow Energy is a JV company based in Brisbane, Australia, that is owned 50/50 by the Shell group and PetroChina (a subsidiary of CNPC). Arrow is planning to develop its tenement holdings of Coal Seam Gas (CSG) in the Surat and Bowen Basins of central Queensland. The CSG will be produced at very low pressures from shallow wells, gathered and compressed into two 500 km trunk-lines for delivery to a two train LNG plant, with each train sized at 4.0 mtpa capacity. The LNG plant will be located on Curtis Island, opposite Gladstone harbour, in Queensland. CSG is classed as "unconventional" gas; this is the first time that Shell or PetroChina have designed an LNG plant with an unconventional gas feed. The paper discusses the unique aspects of integrating an LNG plant with this unconventional gas feed. The main topics covered in this paper are: •Implications of CSG composition for LNG plant design, •Implications of CSG ramp-up for LNG plant design, •Optimising the Availability of the Integrated system, and, •The use of novel design and new technology approaches in the LNG plant in order to reduce costs. Copyright © 2013 International Petroleum Technology Conference.

Bennett T.,Arrow Energy
Society of Petroleum Engineers - IADC/SPE Asia Pacific Drilling Technology Conference 2012 - Catching the Unconventional Tide: Winning the Future Through Innovation | Year: 2012

From by-product to multi-billion dollar industry, the Coal Seam Gas (CSG) industry in Australia has recently experienced rapid growth however is still facing many challenges. The Australian CSG industry is approaching a cross-road; the transition from a Domestic Gas business to exporting the CSG resources, requiring a significant scale up of current operations. Well design innovation is one of the necessary levers to maximize the full potential of CSG as a competitive energy resource. This paper focuses on the technical challenges associated with driving continuous improvement in drilling and completion practices as a key success factor for competitive performance. The growth expected in the CSG industry over the next few years will be rapid. Arrow Energy plans to increase its production from 150 TJ/day in 2012 to 1350 TJ/day in 2018. This will require increases in drilling performance. Much of the early success will likely be obtained from the transfer of benchmark practices, where relevant, from the more mature global oil and gas industry - rather than from true CSG innovation. However, given the lower cost margins and economics of CSG, this knowledge transfer will need to be coupled with innovative application and new approaches. This paper will discuss the importance of innovation in basis of well design as a lever to drive improvements in CSG in Australia and outline some of the key areas that Arrow Energy is focusing on to achieve this, including: • The need for fit for purpose rigs to meet well design criteria and well safety requirements. • Standardization of well designs and equipment aligned to local government regulations and American Petroleum Institute (API) regulations. • Vendor alignment and incentivized performance to meet company targets. • Problems associated with innovation and difficulties of implementation in short time frames as well as the application of lessons learned from trials. • Well design evolution and optimization of gas recovery. • The importance of adopting a culture of learning and flexibility to implement changes as design standards progress. Copyright 2012, IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition.

Gan T.,Arrow Energy | Gan T.,University of Queensland | Balmain B.,Arrow Energy | Sigbatullin A.,Arrow Energy
Journal of Natural Gas Science and Engineering | Year: 2016

Acceptable data quality for formation evaluation forms the foundation for understanding the petrophysical and reservoir properties, coal quality and properties and pay zone identification. The petrophysical logs are used in both subsurface modelling and to optimise the well completion strategy, ensuring effective coal dewatering and desorption for gas production. At the moment, the industry common practice for data acquisition is to use open-hole wireline logging tools, which were developed primarily for the oil and gas industry. These tools are designed for higher pressure and temperature specifications compared to the reservoir conditions normally seen in coalbed methane (CBM), commonly called coal seam gas (CSG) in Australia. This results in heavier tools, larger logging trucks and increased manpower requirements than seen in mining logging operations. Arrow's CBM development projects in Queensland, Australia, are designed with a large number of wells (more than ∼1000 wells) that will need to be drilled and evaluated over the next ten years. At present, the cost of logging (direct wireline contractors and associated rig time cost) is forcing Arrow to choose between early data coverage (reducing project economics) versus restricted logging (increasing project risk). In order to resolve this issue, Arrow has embarked on a series of technology trials to investigate various cost effective formation evaluation solutions, while still ensuring data quality and operational safety. This paper will present the results of a comparison (log-off) of state-of-the-art mining stackable logging technology and conventional oil and gas logging technology. Also, the paper will focus on the mining-style logging technology data quality, equipment footprint, tool handling, calibration procedures, limitations and general operational efficiency. © 2016 Elsevier B.V.

Lagendijk E.,Arrow Energy | Ryan D.,Arrow Energy
Society of Petroleum Engineers - Canadian Unconventional Resources and International Petroleum Conference 2010 | Year: 2010

Arrow Energy intends to develop its certified coal seam gas reserves in the Surat Basin to supply gas to a proposed liquefied natural gas (LNG) plant located in Gladstone, Queensland. The large scale development of the Surat Basin for the LNG Project required basin-wide geological modeling. The Surat Basin coal structure and properties were reviewed in detail and modeled to estimate Gas Initially in Place. Dynamic simulation was subsequently performed to estimate total recoverable volume and generate a robust development plan for the LNG Project. Key subsurface risks consist of access to sufficient gas volumes within the area of interest and gas deliverability to meet and maintain gas supply to the LNG Project. To minimise the likelihood, and to reduce the consequences of these risks, subsurface uncertainties were identified and low and high values for each uncertainty were assessed with the aim to understand impacts on the LNG Project. Gas content, permeability and Net to Gross resulted in the biggest impact on the LNG Project, followed by relative permeability curves, coal heterogeneity, isotherms, permeability variation with pressure, coal compressibility and potential aquifer connection. Other uncertainties, including coal depth cut-off, sorption time and initial reservoir pressure had a lower impact on the number of wells required for the LNG Project. Subsurface sensitivity analysis combined with probabilistics was used to generate 90%, 50% and 10% probability subsurface models. These were carried forward for development planning to generate a range of development outcomes and production forecasts for economic evaluation to ensure a robust LNG field development plan. This paper describes the integrated reservoir data analysis and dynamic modeling methodology for the purpose of the large-scale development of this Surat Basin opportunity and outlines how key uncertainties were identified and addressed. Copyright 2010, Society of Petroleum Engineers.

Gilbert T.,Arrow Energy | Ali E.,Arrow Energy | Mazumder S.,Arrow Energy
Society of Petroleum Engineers - Asia Pacific Unconventional Resources Conference and Exhibition 2013: Delivering Abundant Energy for a Sustainable Future | Year: 2013

A number of coalbed methane (CBM) to liquefied natural gas (LNG) projects are currently advancing in Australia, among which is the Arrow LNG project. To ensure reliable supply to an LNG plant, production availability of the integrated CBM system consisting of a large amount of wells and production facilities needs to be understood, including the behavior of CBM wells after planned and unplanned shutdowns. This paper provides an analysis of post-shutdown recovery behavior of horizontal CBM wells based on a large volume of field data. There is no known published work on shutdown recovery for CBM wells to date, so there are no comparison data. Arrow Energy has produced CBM for domestic consumption since 2004 and currently supplies about 20 per cent of Queensland's gas from fields in the Bowen and Surat basins. A shutdown recovery analysis is conducted on Arrow's Moranbah Gas Project (MGP) in the Bowen Basin. Field data for 6,436 shutdown periods are used, including: gas rates, water rates and bottomhole pressures (BHP). The following effects on recovery times are analyzed: shutdown duration, pre-shutdown water rate, pre-shutdown gas-water ratio, and pre-shutdown producing days. The results indicate that approximately 70% of wells, shutdown for one day, return to 90% of their previous gas rates within one day. Approximately 20% wells recover in a week and the remaining 10% wells come back to 90% of original rates within 2 months. Furthermore, shutdown periods longer than five days have significantly higher recovery times. Wells with a lower water rate and higher gas-water ratio before the shutdown return to their preshutdown gas rate faster than wells with a higher water rate and lower gas-water ratio. Also, late life wells recover faster than wells in early production life. These findings are critical for planning well shutdown and ramp-up strategies (well classifications and priority lists) to manage required gas supply during the operational phase of integrated CBM-LNG projects. © Copyright 2013, Society of Petroleum Engineers.

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