Onshore Gas Research Articles

Report Recounts the Missed Signals Leading to a Blowout That Killed Five

The missed signals leading up to a blowout with the most fatalities since Macondo resembles that offshore disaster. The investigations by the US Chemical Safety and Hazard Investigation Board (CSB) of the blowout on the Pryor Trust 1-H 9 well and Macondo concluded that both were the result of a failure to maintain the barriers needed to prevent an influx of gas into a well. In both cases, the board found a series of missed signals, misleading tests, and miscalculations that allowed gas to build up in a well unnoticed, leading to a blow-out that could not be stopped by a blowout preventer (BOP). Workers died in both cases—11 at Macondo and five at Pryor Trust. An obvious difference is in the level of notoriety. Macondo is still remembered for the destruction of the Deepwater Horizon and an offshore oil spill that lasted for months. The Pryor Trust well was an onshore gas well in rural Oklahoma where a blowout destroyed a rig in the morning and the fire was put out that afternoon. There was little media coverage. The environmental impact was minimal, and the companies involved, Patterson-UTI Drilling and Red Mountain Energy, are not well known. Still, it provided a stark warning of the risks associated with some widely use drilling practices. “Our investigation found significant lapses in good safety practices at this site. For over 14 hours, there was a dangerous condition building at this well,” said Kristen Kulinowski, interim executive at the CSB, a federal agency that investigates major accidents, in a statement on the report. “When the blowout mud and gas ignited, it created a massive fire on the rig floor. All five of the workers inside the driller’s cabin were effectively trapped because fire blocked the driller’s cabin’s two exit doors,” said Lauren Grim, a CSB investigator who noted there is no guidance to ensure that an emergency evacuation option is present. “The investigation revealed that there are no regulations specifically developed for onshore oil and gas well drilling,” the statement said. It explained that while the Occupational Safety and Health Administration (OSHA) does monitor oil and gas operations under a clause that “protects workers from serious and recognized work-place hazards,” onshore exploration and production (E&P) is exempt from the OSHA process safety management standard. Offshore oil and gas process safety is regulated by the US Bureau of Safety, Environment, and Enforcement. The report said onshore E&P operations should be subject to OSHA’s process safety standard to “addresses the hazards unique to the onshore drilling industry.” The CSB asked the American Petroleum Institute (API) to provide recommendations to fill these gaps.

Competing risks survival analysis of ruptured gas pipelines: A nonparametric predictive approach

Risk analysis based on historical failure data can form an integral part of the integrity management of oil and gas pipelines. The scarcity and lack of consistency in the information provided by major incident databases leads to non-specific results of the risk status of pipes under consideration. In order to evaluate pipeline failure rates, the rate of occurrence of failures is commonly adopted. This study aims to derive inductive inferences from the 179 reported ruptures of a set of onshore gas transmission pipelines, reported in the PHMSA database for the period from 2002 to 2014. Failure causes are grouped in an integrated manner and the impact of each group in the probability of rupture is examined. Towards this, nonparametric predictive inference (NPI) is employed for competing risks survival analysis. This method provides interval probabilities, also known as imprecise reliability, in that probabilities and survival functions are quantified via upper and lower bounds. The focus is on a future pipe component (segment) that ruptures due to a specific failure cause among a range of competing risks. The results can be used to examine and implement optimal maintenance strategies based on relative risk prioritization.

Natural gas extraction and community development in Tanzania: Documenting the gaps between rhetoric and reality

The Tanzanian government recently adopted new legislations to reform its oil and gas sector, for the purpose of safeguarding its interests and serving the developmental aspirations of its ordinary citizens. While laudable in spirit and content, these reforms have raised questions about their implementability, particularly with regard to their developmental impact on all Tanzanians. Drawing on fieldwork conducted in the natural gas producing coastal region of Mtwara, including a large-scale household survey, this paper contrasts policy articulations with local community expectations and household perceptions, attending to the different ways in which gas development activities have affected communities near on-shore gas fields and gas processing plants. While the rhetoric of gas-driven prosperity has contributed to high expectations among communities in the gas producing region, it has not translated into reality for most individual households. This gap reflects the centralized character of resource governance, the inconsistent way policies pertaining to natural gas development have been framed and reframed, the unrealistic expectations of prosperity that have pervaded national and local discourses on the gas discoveries, the lack of public consultation, and state-directed violence. The paper contributes empirically to the literature and on-going debates about the extractive sectors’ impacts on project-affected communities.

Onshore Oil and Gas Design Schedule Management Process Through Time-Impact Simulations Analyses

Korean oil and gas contractors have recently incurred significant losses due to improper engineering performance on EPC (engineering procurement and construction) projects in overseas markets. Several previous studies have verified the significant impact engineering has on EPC construction cost and project lifecycle. However, no literature has studied the time impact engineering has on EPC projects, representing a gap in the existing body of knowledge. To fill this gap, a Monte Carlo simulation was performed with the Pertmaster, Primavera risk analysis software for three sample onshore oil and gas projects. From said simulation of all major EPC critical activities, the authors found that the engineering phase is up to 10 times as impactful as the procurement and construction phases on the overall schedule duration. In assessing the engineering activities, the authors found the piping design activities to have the greatest impact on the overall schedule performance. Using these findings, the authors present a design schedule management process which minimizes the delays of project completion in EPC projects. Said process includes the following six steps: (1) Milestone management, (2) drawing status management, (3) productivity management of engineering, (4) interface management, (5) management of major vendor documents, and (6) work front management. The findings of this paper add to the body of knowledge by confirming the design phase to be the most impactful on the overall project schedule success. Furthermore, the presented design schedule management will aid industry with successfully executing the design phase in a timely manner, including examples from case study projects for a greater understanding.

Onshore gas industry coexistence in Queensland

Modern onshore gas development in the Surat Basin, Queensland, coexists with communities who have farmed land for multiple generations. Both agriculture and the gas industry bring different values, methods and cultures to these communities. CSIRO GISERA’s social research over the last six years in this region has documented community attitudes towards development of the industry. We have found that communities which adapt relatively well to industry development and operation are characterised by high quality environmental stewardship, abundant economic opportunities, strong community cohesion, and, trust in local decision making where information is transparent and shared. Conversely, adaptation by communities is relatively poor where procedural fairness is perceived to be distorted in favour of governments and the industry, governance procedures are not trusted, and, economic opportunities are not realised. These measures of acceptance of the gas industry change very slowly over time – on decade timescales rather than years and, hence, our work falsifies the misconception that it is possible to ‘manage’ community perception of the industry in the short term. Social acceptance of the gas industry is a complex interaction between perceived benefits and impacts of the industry, distributional fairness of those benefits and strong governance; particularly with regard to environmental regulation and protection of water resources. Robust, world class and trusted science has an important role to play in informing community understanding of the impacts and benefits of the industry and through this influencing the gas industry’s social acceptance. To view the video, click the link on the right.

Natural gas separation at CO2CRC's Otway National Research Facility

CO2CRC, in collaboration with the University of Melbourne and the University of New South Wales, is testing two novel CO2 capture technologies designed for both on-shore and off-shore natural gas applications in a state-of-the-art experimental capture rig at CO2CRC’s Otway National Research Facility. The goal is to develop robust and compact technology for high pressure natural gas separation over a range of adjusted high CO2 concentrations mimicking various gas field conditions. These technologies would facilitate developing new gas fields to recover methane in a cost-effective manner which is currently uneconomical with conventional technologies. In the first stage of testing, commercially available materials (adsorbents and membranes) were used for benchmarking. Results from both adsorbent and membrane technologies are encouraging with respect to recovery and purity of CO2 and methane with the prospect of commercial application.

Aspects of protection against carbon dioxide corrosion of gas production facilities

The modern stage of development of many onshore and offshore gas and gas condensate fields is associated with objects in which carbon dioxide (CO2) gas is present in the production. The presence of CO2 in the produced gas in combination with other factors stimulates the intensive development of corrosion processes, which requires careful and reasonable attitude both to assess the degree of aggressiveness of the media and to choose technical solutions to ensure reliable and safe operation of hydrocarbon production facilities. The authors analyzed the existing approaches to the assessment of the danger of corrosion produced media, selection and implementation of protection against corrosion in the presence in them of aggressive CO2.

Old rocks, new tricks: a reinvigorated Cooper Basin offers growth opportunity

The Cooper Basin spans north-east South Australia and south-west Queensland and is Australia’s largest integrated onshore oil and gas development. Santos and Delhi first discovered commercial gas in 1963. First oil was discovered in 1970. Since then, the Cooper Basin has become a strategically important processing and transportation hub for produced gas and liquids. Continuous investment in new technology, the use of existing infrastructure and, recently, an unrelenting drive to lower drilling and production costs has delivered a low-cost, high-margin producer for east coast domestic and liquefied natural gas (LNG) export markets. This improved operating performance has, in turn, offered Santos the opportunity to reassess ‘our backyard’. The Cooper Basin boasts many growth options, remaining and emerging. Seismic advances are providing improved imaging. Data management, the use of play-based exploration studies, innovative geoscience thinking and renewed investment risk appetite are playing key roles in the development of discovered resources and the exploration of new and emerging plays. Targeted wildcat exploration and appraisal programs, supported by low-cost operations, offer the potential to unlock significant remaining oil and gas resources. The Cooper Basin is poised for another stage of growth. This tangible potential emphasises the critical future role the basin is likely to continue to play as an onshore Australian hydrocarbon supply hub.

Groundwater management – working with Queensland and EPBC regulation and processes

Onshore gas development projects are often referred for assessment under the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act), administered by the Commonwealth Department of the Environment and Energy (DOEE), and coal seam gas projects may require additional assessment under the ‘water trigger’ legislation. Queensland Government approval is also required and both governments’ approval processes can intersect. The two processes may have different scope and timeframes, and these are important considerations for proponents bringing forward new gas supply and project expansions. As co-regulators, the Queensland Government and DOEE routinely look for opportunities to better align regulatory practices and ensure they remain contemporary and fit for purpose. In this context, they are exploring opportunities to improve the administration of requirements for Queensland gas projects to enhance the ability of regulators to assess project approvals, ensure compliance, improve process efficiency, and maintain high environmental standards.

Zero Waste Well – the beneficial use of produced water from CSG projects

Most onshore gas provinces in Australia are in remote locations where it is expensive to bring materials to, and take waste away from, well sites. Importantly, water is not only an input to, and a product of, the drilling, completion, construction and production process, it is also a precious resource. That is why Santos has been working towards the ‘Zero Waste Well’. Historically, separate drilling, completion, construction and operational teams were involved in sourcing and disposing of water without taking a holistic view of the water cycle. By taking a collaborative approach and looking at the complete water cycle, Santos has been able to reduce its water use and eliminate wastewater by reusing all of the produced water in its Queensland coal seam gas upstream activities for beneficial purposes. As part of the Zero Waste Well concept, Santos has identified and implemented a range of initiatives for beneficially reusing produced water. These include stock watering, construction, dust suppression, rehabilitation, and drilling and completion activities. One of the most exciting innovations is to beneficially reuse produced water for localised irrigation. This avoids or minimises the need for large centralised water gathering systems and large static centralised water storages and treatment plants. This also minimises the environmental footprint, energy intensity, carbon emissions and brine wastes from Santos’ activities. Localised irrigation not only reduces construction and operating costs, and engineering design and construction timeframes for Santos, it provides a valuable pasture irrigation source for local landholders.

Australia's shale industry – how we can become globally competitive

Project delivery technology is changing and developing at a rapid rate, and Australia’s oil and gas industry could do a better job of embracing change and getting to the forefront of advanced digital technology applied to developing onshore gas resources – particularly to our vast undeveloped shale reserves. Our shale deposits are in remote parts of our country, so present significant challenges, especially in relation to geographical distance away from local and international markets. This paper will focus on the use of automation and standardisation in the engineering design process combined with project execution strategies to significantly reduce both schedule and cost in delivering surface infrastructure required to get our gas shale reserves to both domestic demand centres and export facilities. The traditional project delivery models that have served us well in the past need to be challenged and a new paradigm adopted. Standardisation of the compression and dehydration facilities in the US market has been developed over many years, resulting in efficient project delivery, and enabling reserves to be brought to market on a fast track basis. This paper will work through practices in the US and how they can be applied to Australia. Australian standards and industry practice defines how we design our gathering and pipeline networks. This paper will present a combination of construction strategies and automation of engineering design to optimise life cycle cost in remote regions where construction mobilisation and logistics is a significant factor combined with changing priorities as further reservoir data is obtained from exploration wells.

From the Beetaloo to West Texas: similarities, differences and lessons learned from water management in coal seam and shale field developments on either side of the Pacific

Water management presents a host of challenges and opportunities for operators developing unconventional onshore gas fields. Water supply, recycling and disposal issues affect each stage of field development and operation. Sourcing water and production of produced and flow back water has important implications for water availability and management of the unique environmental risks. All water source and produced water decisions come with costs. From the treatment and reuse of coal seam gas (CSG) produced water, through to the storage and ultimate disposal of water containing elevated salinity and organic loads in shale fields, the costs for water management fundamentally contribute to the economics of unconventional gas developments. In this paper, we will draw on experience in both CSG and shale field water management to compare the respective water management challenges and opportunities faced by operators in these industries. A series of case studies will be used to highlight the differences between the CSG and shale fields. This will include assessment of a West Texas shale field development, where field specific data, such as well-to-well distance and travel time between them, has been used to identify and compare produced water management options. We will use these indicators to demonstrate how alternative ways to assess produced water options, based on economics, can reveal creative management strategies that achieve a variety of goals at every stage of field development, including maximising reuse and minimising disposal.

Approaches to data-driven exploration in Queensland

Queensland has a very significant petroleum resource endowment within 27 hydrocarbon basins spread across the state. Three of those basins already host Australia’s largest onshore gas supply industry, leaving significant opportunity to develop additional gas resources. To optimise the development of new resources, the Geological Survey of Queensland (GSQ) is implementing an integrated approach to exploration and appraisal called ‘data driven exploration’. Working in collaboration with industry, the research sector and relevant government agencies, GSQ is promoting data-driven exploration in four ways: by (1) optimising the type and quality of geoscience data collected and reported by industry; (2) improving data curation practices in government data repositories; (3) creating value-added opportunities for the use of geoscience data; and (4) improving industry capability and capacity through skills enhancement, collaborative mechanisms, and access to an expert capability network. The overarching objective of ‘data-driven exploration’ is to enable industry exploration and appraisal success by making best use of geoscience data coupled with supporting mechanisms to improve competency and capability to derive, interpret and employ geoscience information. The expression of success will vary depending on individual circumstances, but is intended to encompass a range of outcomes including improvements in the rate, cost and efficiency of discovery and appraisal.

Next Generation Reservoir Engineering

We present a fundamental physics based understanding of the chemical, mechanical, thermal and hydrological processes and their interactions that operate over long-time scales to form and characterise the porosity/fracture networks in conventional and unconventional oil and gas reservoirs. We apply that understanding to engineer that structure for the purpose of energy extraction and resource discovery. The interdisciplinary approach links geoscience, engineering and computational science disciplines with the result of providing a step change in exploration and exploitation technologies with significant reduction in onshore gas development costs without compromising OHSE or environmental protection and assurance. In this presentation, we will show the first results that allow incorporation of important processes in Unconventional Plays. Surprisingly, diagenetic processes such as the smectite-illite transition are found to create natural fractures under tectonic load that form the permeable reservoirs in Shale Gas/Oil Reservoirs. Results indicate that the fractures triggered by natural fluid release reaction on geological time scales are supported by a critical fluid pressure that must not be crossed to avoid sudden loss of the reservoir. Upon crossing this threshold reservoir damage can be substantial. No amount of proppant or other engineering interaction can rescue the reservoir on a human time-scale. Our novel framework allows to link the long-time scale geological processes with the design of an injection-extraction protocol to maintain critical fluid pressure. We are also able to incorporate micro-structural changes and fluid-solid interaction at grain scale. The latter has only been benchmarked for conventional carbonate plays, but the Multiscale results are encouraging for the entire spectrum of conventional and unconventional traps/source rocks. Our theoretical framework and the forward simulator is specifically designed to interface with geophysical inversion techniques for multi-scale geophysical data. Completing this data-assimilation step in the future will define Next Generation Reservoir Engineering.

Resource Growth Through Petroleum Exploration in PNG

Mesozoic and Tertiary clastic and carbonate reservoirs are prolific producers of high quality liquid-rich gas onshore PNG. LNG projects are among the lowest cost and most profitable globally. Accordingly there has been a recent resurgence of petroleum exploration in PNG.In 2015 Oil Search undertook a country-wide petroleum Common Risk Segment analysis that highlighted potential for giant new oil and gas fields of sufficient scale to support future LNG projects. It also concluded that 40 trillion cubic feet of gas plus 550 million barrels of oil resources remain to be found (representing approximately 60% of PNG’s total petroleum resource).In 2016 Oil Search completed an ambitious integrated structural, stratigraphic, burial, maturation, migration, uplift and erosion model of PNG’s total petroleum system to quantify the locations for highly prospective under-explored regions.Tectonic events at plate and basin scales were re-assessed and correlated within a new country-wide PNG Chrono-stratigraphy of regionally mappable sequences and flooding events, some of Global extent.A Base Tertiary Mega-Sequence Boundary is mappable over the entire onshore to deepwater regions. 130 1D burial models combined with restored 2D structural and stratigraphic cross sections, have contributed to a new regional petroleum charge model of the Foldbelts, Foreland and Offshore regions.It is concluded that petroleum was generated pre- foldbelt during Late Cretaceous times in interior PNG while petroleum is currently being generated at the present day mountain front.A holistic 4D charge model explains why very young foldbelt traps are petroleum charged.

Security and the Subsurface: Natural Gas and the Visualisation of Possibility Spaces

ABSTRACTBeneath the surface of the United Kingdom lies a sprawling natural gas infrastructure. Based on recent (2014/15) ‘follow the thing’ fieldwork conducted in the UK onshore gas industry, this paper explores the ways that dangers related to the subterranean circulation of natural gas come to be visualised, and how these visualisations make possible different security interventions. These practices are shown to be limited by the ground, which despite its enrolment as a security device conceals from view the shifting landscapes of risk that surround these gaseous movements. Drawing on Manuel DeLanda's concept of the possibility space, I provide a conceptual framework for attending to security’s visualisation practices, describing how attempts are made to overcome the subsurface obfuscation of natural gas. I argue that, rather than being understood as a process of circulatory ‘filtration’ or ‘maintenance’, security must instead be regarded as a series of transformative practices of ecological (re)organisation that are predicated upon the visualisation of entities’ spaces of possibility. In the process, I provide an account of how the three-dimensional geographies and materialities of gas circulations and their milieus are intimately tied up in their governance and politics.

Is the gas industry a good neighbour? A comparison of UK and Australia experiences in terms of procedural fairness and distributive justice

Australia and the UK share much in common in their social, governance and legal systems. Would approaches to unconventional oil and gas development also be similar? In this article, we examine the different experiences of local communities regarding unconventional oil and gas development in Queensland, Australia and England, UK. We question whether the onshore gas industry makes a ‘good neighbour’ in two different contexts that share one common legal background. We consider procedural fairness within the context of land access processes and discourses of individual and collective property rights generated by unconventional gas development in each country. Land access policy and practice have developed significantly in Australia to recognise the rights of existing landholders, including Traditional Owners, and in England, to clarify mineral and resource ownership rights. We consider distributive justice within a conceptual framework of social sustainability relating to communities and local social impacts from development. We review how governments at various levels have attempted to resolve such issues. We conclude that the unconventional gas development experience is heavily context dependent and cannot be described by a simple narrative, nor by snap-shot baseline and impact studies. We suggest that there remains much to be learned about regulating the industry.

An algebraic targeting approach for optimal planning of gas sweetening problem in non-conventional gas field development

Abstract An algebraic technique based on pinch analysis has been developed for the planning of non-conventional natural gas (NG) field development projects. The development of NG fields with high carbon dioxide (CO2) content has become increasingly common in the oil and gas industry. In such cases, the raw NG needs to be treated in situ for CO2 removal to meet the sales gas specifications before being sent to the onshore gas processing plants (GPPs). The captured CO2 can either be reinjected into the reservoir for permanent storage, or utilised for enhanced oil recovery (EOR), for which partial sequestration may also be achieved. These options create the need to develop systematic techniques to provide high-level decision support for field development planning. The algebraic technique developed in this work overcomes the limitations of a recently developed graphical technique ( Foo et al., 2016 ), as it relaxes the previous simplistic assumptions on stream purity requirements. Two case studies are used to illustrate the methodology.

Guest Editorial: Putting the Power Into Empowerment To Drive Digitalization

Guest editorial It is time to put a common misconception to rest. The oil and gas industry is not lagging behind other industrial sectors in the race toward digitalization. We are leading the charge. This confidence is born from our status as one of the earliest adopters of digital technologies to efficiently transform complex reservoirs into revenues. However, two things have happened since our industry first started adopting digital in its original form several decades ago. First, oil and gas businesses are experiencing new pressures from the downturn, which has placed increased focus on productivity and the navigation of diverse energy dynamics. Second, the Industrial Internet of Things (IoT) or Digital 4.0 technologies have developed at an increasing rate, with the democratization of cloud computing and the advancements in data analytics, artificial intelligence (AI), and machine learning creating new opportunities beyond the consumer space. The resulting environment is one in which the oil and gas industry must consider the role these new digital technologies will play in navigating shifting industry dynamics. While the industry is at a prime point, testing and beginning to put to work new digital ideas, the draw to return to age-old, tried and tested methods can be tempting. Unlike vehicle manufacturing, we are truly a process-driven industry where simulation, data measurement, and modeling are at the core of everything oil and gas does because everything is connected. We must move forward to adopt industrial IoT technologies that optimize across assets, processes, people, production, and the reservoir and wells by delivering answers in real time. Harnessing data that have been stranded will improve reliability, optimize production, and transform overall operations beyond what existing, siloed software solutions were able to deliver. The value in data analytics at scale across an enterprise is visualization of historical and real-time performance across an entire business, from the reservoir and well to the refinery. Connecting digital across oil and gas businesses will be a key topic at the inaugural ENGenious conference and exhibition taking place in Aberdeen, 4–6 September 2018. Four key pillars of activity will be on the agenda: data analytics, automation and control systems, robotics, and smart communications. While the event will explore what innovation means for the onshore and offshore upstream oil and gas industry, it will embrace the learnings and experiences from a diverse range of industries. Using an ecosystem approach, this will create an enlightening forum to encourage cross-pollination of ideas and information exchange.

An integrated risk assessment of onshore gas transmission pipelines based on defect population

The aim of this research is to develop an original probabilistic method for an underground onshore gas transmission pipelines maintenance risk estimation. The method considers a population of the anomalies detected by an in-line inspection . In the methodology, features are considered as a family with certain defect depth and shape distribution derived from the repeated in-line diagnostics of a steel pipeline under operation. A growth rate in the radial direction is determined based on a defects size change between two or more inspections. The number of non-detected hypothetical anomalies were taken into account due to probability of detection and sizing uncertainties by means of a non-perfect inspection device. Metal losses of the pipe wall are assessed by a fracture mechanics method based on a limit load theory and considered as a leak or rupture. Gas pressure distribution and temperature along the pipeline are calculated in steady state conditions. Particular attention was paid to the evaluation of the probabilistic pipeline failure consequences to the surrounding area with parameters as population density and road traffic taken into consideration. Although the presented risk estimation is universally applicable, the novel methodology was applied to the high pressure gas transmission pipeline situated in the area similar conditions typical for Europe. The failure probability calculations are carried out for different pipeline modes of the fluid transportation. A significant connection of the risk evaluation with pressure distribution along the pipeline was observed based on the differences in risk distributions between Summer, Autumn and Winter operational modes.