bluuebunny/crossref_metadata_2025_split huggingface dataset:
Australia's World Scale Gas Resources, Its Markets and Why New Approaches Are Required
Authors: Towler Brian , Firouzi Mahshid , Wilkinson Rick 
Published: October 2018

Abstract
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
Controls on CH4 Adsorption on Shales: Characterisation of Beetaloo Sub-Basin Gas Shales and Comparison to Global Shales
Authors: Sander Regina , Pan Zhejun , Connell Luke D , Camilleri Michael , Grigore Mihaela 
Published: October 2018

Abstract
The Beetaloo Sub-basin in the Northern Territory is one of Australia's most prospective basins for shale gas production. The Beetaloo gas shales are unique in that they could become some of the oldest producing source rocks in the world, if commercialized successfully. In this work we characterise gas shales from two target reservoirs in the Beetaloo Sub-basin and compare them to other shales from around the globe to improve the current understanding of what controls gas adsorption on shales.
We characterise the methane adsorption capacity of two sets of Beetaloo shale samples: middle Velkerri B shale (8 samples, ~2450 m depth) and lower Kyalla shale (10 samples, ~1300 m depth). Measurements are performed at reservoir conditions, i.e. up to 110°C and 30 MPa, using CSIRO's gravimetric isotherm rig. The samples’ mineralogy is analysed using X-ray powder diffraction (XRD) and the total organic carbon (TOC) is determined using a LECO machine.
Our experiments demonstrate that the gravimetric rig is capable of obtaining fast and reliable measurements on low adsorbing shales at high pressures and high temperatures for sample quantities of around 90 g. The results highlight that the adsorption capacity of middle Velkerri B shale is significantly higher than of lower Kyalla shale (average Langmuir volume 3.23 m3/t compared to 2.27 m3/t) and that the isotherms can be represented using a Langmuir relationship. In spite of their age, the Beetaloo shales exhibit adsorption behaviour comparable to that of other shales with similar TOC.
Two global shale data sets, which include the Beetaloo samples, demonstrate that there is a strong relationship between TOC and a shale's adsorption capacity. However, the TOC alone cannot account for the differences in adsorbed amount observed within the two sets of Beetaloo shale samples.
Bulk clay content appears to control the adsorption capacity of shales with low TOC (&lt; 2%), such as the lower Kyalla shale. Analysis assessing the contribution of individual clay minerals to the CH4 adsorption capacity indicates that it is the high illite/muscovite content (30-40%) that controls adsorption on the lower Kyalla shale samples. For the high TOC/low clay middle Velkerri B samples (3.7-6.3% TOC, 20-23% clay) clay content cannot account for the differences observed in adsorbed gas between the samples, even as a secondary control. Further investigation is required to understand what controls gas adsorption on this shale.
A Case Study: The First Hydraulically Fractured Well in Carbonate Reservoirs in Iraq
Authors: Cui Mingyue , Ding Yunhong , Zhu Dawei , Chen Yandong , Cai Wenxin , Liang Chong , Hu Zihui , Yan Jun , Wang Dayong , Zhang Tianwen 
Published: October 2018

Abstract
The reserves of tight carbonate S formation amounts to 25% of the total of X field in Iraq, but the production contributed only 0.3% to the total output. Accordingly, hydraulic fracturing was implemented in well V5X in Dec. 2016, the first pilot test in Iraq. In this paper, the fractured well was taken for a case study to illustrate the holistic optimization to guarantee the treatment success, a world-wide difficulty with high engineering risk.
There are uncertainties concerning the breakdown pressure, in-situ stress and the development of natural fissures in the region, posting challenges in figuring out a reasonable treatment design.
For this purpose, comprehensive lab experiments and numerical simulation were conducted to analyze and benchmark the reservoir characteristics, rock mechanics and geological model. Systematic study on fracture parameters optimization, treatment fluid formulation, proppant screening and operation program were carried out. Based on the treatment parameter optimization, the main-frac scheme was perfected in combination with mini-frac and temperature logging interpretation.
S formation is a limestone reservoir with unique petrophysics, i.e., medium to high porosity (15-20%) but low permeability (0.05-1.3 mD), poor connectivity between pore throats, and hence resulting in inadequate liquid supply. Lab experiments revealed the "low Young's modulus and high Poisson's ratio" rock mechanics features, which is contrary to common understanding. In this case, large-scale treatment was required to ensure the high fracture conductivity. Moreover, there is no significant contrast in the in-situ stress profile or lithology barrier. Consequently, the development plan which requires fractures to be constricted within S formation would be hardly realized. Therefore, proppant sizing was prudently conducted to achieve the rational sand placement and treatment fluid performance was optimized to control the vertical fractures extension. For the fracturing job, totally 443.1 m3 treatment fluid and 39.6 m3 proppant were pumped. The operation parameters were in reasonable agreement with the design. The initial test production was 10 times higher than before. Currently the "production under controlled pressure" mode has been executed. The wellhead pressure has been stable, and the boosted production has been maintained for over one year. Comprehensive analysis of reservoir characteristics and suitable fracturing design are crucial to the success of stimulation treatment.
The experience gained in this case study has some guiding significance for improving the success rate of hydraulic fracturing treatments and for effectively developing such low permeability carbonate reservoirs, both theoretically and practically.
Mitigating the Failure of Downhole Pumps Due to Gas Interference in Coal Seam Gas Wells
Authors: Wu Benjamin , Firouzi Mahshid , Rufford Thomas E. , Towler Brian 
Published: October 2018

Abstract
Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [1] available in the open literature. A review of more general studies on two-phase gas-water flows in vertical pipes and annuli revealed that experimental conditions, especially pipe and annuli diameters, can have a significant impact on development of two-phase flow phenomena. As such, the limited available data may not be applicable due to differences in experimental conditions. This study experimentally investigates the onset of gas carryover using an experimental setup intended specifically for the study of CSG wells.
The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.
Mechanisms Investigation of Super-Heated Steam Assisted Gravity Drainage
Authors: Liu Xueqi , Liu Shangqi 
Published: October 2018

Abstract
The heat efficiency of steam during SAGD process is vital for the SAGD economic performance. In deposits with buried depth more than 400 meters, the in-situ steam quality is basically less than 85% by injecting the saturated steam on the wellhead. Less steam quality means less specific heat enthalpy and less effect of oil viscosity reduction by steam and lower oil drainage rate. The super-heated steam injection was proposed in this paper in which the key mechanisms of oil drainage rate enhancement were investigated for a typical SAGD project in Athabasca oil sands.
The experimental and numerical simulation approaches were chosen to integrally study the key mechanisms. A serial of two dimensional scaled physical modeling were performed to simulate the characteristics of steam chamber evolution, to compare the dynamics of SAGD production by different steam temperatures, and to determine the potential of SAGD by super-heated steam. In addition, the field scale numerical simulation model was built based on the geologic modeling, and the relationship between steam temperature and steam chamber growth behaviors were studied.
The two dimensional scaled physical modeling results indicated that the steam needed was reduced by elevating the steam temperature, and less time was required to reach the plateau oil production rate. Super-heated steam with higher temperature speeded up the steam chamber growth rate more evidently, while when the super-heated value was more than 300°C, further enhancing the temperature would result in less incremental oil drainage rate and higher risk of caprock failure. The numerical simulation of typical SAGD wellpair required that the overall temperature of super-heated steam should be not above 300°C considering the lifting requirements and hydrothermal reaction. 7.67% of less steam injection for the whole life cycle of SAGD, 13.5% of reduced SCOR would be achieved by steam with super-heated degree of 40°C.
The results from this paper have been used to guide the field operation, and the encouraging performance was expected.
Malaysia's Experience in Integrated Coordination of Offshore Supply Vessels through Integrated Logistics Control Tower ILCT
Authors: Mohammad Nurul Azni , Mohd Azani Muhammad Faiz 
Published: October 2018

Abstract

1. Objectives/Scope
The Integrated Logistics Control Tower (ILCT) aims to enable vessel sharing across 15 Malaysia producing Petroleum Arrangement Contractors (PACs) to lower the logistics cost across upstream operations in Malaysia. Prior to this, each PAC operated their own vessels. Opportunities for synergy and sharing between PACs were rarely tapped resulting in fragmented demand and specification, which in overall leads to higher cost.

2. Methods Procedures, Process
ILCT was triggered from a heuristic study in June 2016 and the study showed the potential of RM100 millions yearly cost saving from reduction of 10-20 vessels through fleet sharing across the producing PACs. A joint project management team was formed comprised of key logistics personnel from PETRONAS and PACs to execute ILCT. Operation simulations were conducted involving stakeholders from operations, Health, Safety and Environment (HSE), legal, finance, and procurements to identify current limitations, and the short, medium and long term solution in order to ensure such sharing will not compromise HSE and production performance.

3. Results, Observations, Conclusions
The joint project management team has encountered multiple obstacles towards ILCT implementation such as vessel priority, marine HSE standardization, vessels technical specifications, joint coordination agreement, liabilities, cost allocation, accumulative contract value re-distribution, and governance matters. In overcoming the obstacles, the team has established ILCT Committee and ILCT Manual. The ILCT Committee comprises of PETRONAS and PACs members with the key roles to control the overall allocation of vessels, mediate any conflict, and improve ILCT performance. The ILCT Manual was jointly developed by PETRONAS and PACs to govern the implementation of ILCT and is regularly referred by PACs as guiding principle in operating vessels.
This national synergy resulted in 12 vessels reductions from 142 to 130 vessels that equivalent to RM100 millions of cost savings yearly. PETRONAS and PACs benefit from this synergy mainly through optimized traveling route, which results in lower Daily Charter Rate and fuel cost. It also supports PETRONAS’ agenda to nurture capabilities of local vessel owners to become regional vessel operators. The key success of ILCT lies on PETRONAS’ role as the regulator for Malaysia upstream industry, by orchestrating the cooperation across PACs in syncing the common alignment towards achieving the desired outcome of ILCT.

4. Novel/Additive Information
Malaysia's ILCT is the biggest integrated offshore marine transportation arrangement in the world, with 120 vessels involved in serving offshore transportation needs to 198 producing fields in East & West Malaysia.
From Preservation to Execution: Value Creation through Successful FDP Optimisation for an Offshore Green Field Gas in Peninsular Malaysia
Authors: Sabzabadi Ali , Binti Daeng Aida , Binti Hamza Norashikin 
Published: October 2018

Abstract
Value Creation can be achieved through FDP optimisation initiative for offshore fields that have been impacted by recent slump in activities and investments in the Oil and Gas industry. Each stage of the FDP process can be reviewed and respective value and cost target be revised. It is to ensure that process for the opportunity still carry business value, and aligned with business objectives at current industry outlook. Alongside the opportunity maturation process, there should also be emphasis on value assurance to maximise value and chance of success.
Offshore development of a green field gas development in Peninsular Malaysia was a successful story of Integration and engagement of various functions and disciplines throughout the FDP optimisation efforts, by keeping the FDP stages as "live" cycles. It let the optimisation process to encompass all activity spectrum from subsurface to surface, and warranted the project to be fully assessed from uncertainties and risk management to optimising the value of the project.
Early determination and understanding of the objectives and area of focus for maximum impact on value creation initiatives were chosen to be the road map. Moreover, collaboration between the teams to revise drilling, completion and the depletion strategies with capital cost phasing were identified to be key areas for a successful development and cost optimisation of the project. Drilling and completion strategies for the wells selected in a manner that they focused on most productive zones at the beginning, with development of the shallower reservoirs by workover and intervention activities upon depletion and pressure equalisation with the lower zones. The strategy also led the capital cost to be classified as operational as future expense without compromising the reserve to be developed.
The result of the work led to a significant cost saving which in turn allowed execution of the project from preservation to drilling stage in almost 6 months.
This paper will highlight the initiatives and activities that made the project to be successfully move from preservation to execution mode.
Using a Business Intelligence Tool for Drilling Data Analysis in the Permian Basin
Authors: Chen Zhenyu , Lo Allen , Neves Carrasquilla Maria , Zhao Zhiguo , Shahid Tanveer 
Published: October 2018

Abstract
Oil and gas companies are increasingly using data analytics to improve drilling performance. This paper provides an example of using a business intelligence (BI) tool to analyze drilling data in the Permian Basin. The BI tool helped to improve operation decisions through the use of a visual report. A database, consisting of massive amounts of historical drilling data, is analyzed using the BI tool to better understand drilling performance and predict average operations performance in the area.
A historical drilling database is created based on the bottomhole assembly (BHA) run data and analyzed by the BI tool to review the well performance, in addition to identifying any hazards and summarizing the optimum drilling system during the planning phase. With the help of the BI tool, the drilling database can be displayed in an interactive way to further understand the drilling performance in the area; e.g., the top performing drill bit, drilling system, downhole mud motor configuration, and estimated drilling time for the section of interest. As a result, engineers will find it easier to identify the potentially top performing wells along with drilling hazards in offset wells. The engineers can evaluate the well details and identify the best drilling practices to optimize drilling performance and eliminate downhole incidents.
Using the BI tool helps reduce the data mining time and offers a fast, improved method for gaining technical insights into the drilling operation. These descriptive analytics help to simplify the complex data sets, which are valuable for uncovering patterns that offer data set understanding. With the visualization results, experts can focus on data diagnostics analytics to make suggestions for drilling operation improvements and corrections. Furthermore, these analytical data can be used as inputs for more advanced predictive (forecast drilling performance) or prescriptive analytics (drilling optimization) that deliver real-time insights for making improved business decisions.
Performance of Ceramic Sand Screen for High Rate Gas Application - Gas Sand Screen Erosion Testing
Authors: Manning Nickolas , Cadogan Paul , Barth Peter , Hoskin Ben , Read Trent , Manning David , Jackson Richard , Gundemoni Bhargava 
Published: October 2018

Abstract
Sand production is a common problem throughout the oil and gas industry, particularly in ‘high rate’ gas reservoirs coupled with low rock compressive strength. Conventional downhole sand control techniques such as gravel packing can act to limit both well geometry and/or productivity. Furthermore, problems with gravel pack installations can lead to preferential inflow, leading to ‘hot spotting’ and ultimately loss of sand control. To evaluate the erosion resistance of sand control equipment under the highly erosive environment of high rate gas wells, innovative testing equipment is needed. This paper will discuss the development of a Gas Sand Screen Erosion Test (GSET) rig and its application to evaluate the erosion resistance of ceramic sand screens.
GSET is designed to simulate ‘accelerated’ erosive down-hole conditions. The GSET cell can accommodate but not limited to a screen stub section, screen coupons and variety of downhole equipment. A combination of high flow rate gas and volume controlled particle reservoir matched sand is coalesced into an acceleration tube. The high velocity sand particles (&gt;80m·s-1) impact the ceramic sand screen, causing erosion within the target area. In this paper, the GSET rig was operated for 48 hours at maximum velocity (&gt;80m·s-1) and with a sand concentration of 750 ppmw. Take into consideration that the velocities seen throughout this paper are significantly greater than what a conventional reservoir/completion system would have to tolerate.
Initial and final sand screen analysis was conducted to evaluate the performance of erosion resistance. An array of analysis techniques was applied with focus on gap aperture size and surface topography. Gap aperture measurements were a focal point, as it is directly proportional to its ability to maintain sand retention capabilities.
This paper highlights the potential of the new GSET rig, enabling laboratory testing of erosion resistance of sand control equipment for high rate gas wells under accelerated conditions. Test results obtained with the ceramic sand screen section underpin the inherent high erosion resistance of ceramic sand screen technology ensuring longevity in highly erosive environments. Thus, providing opportunities to complete both new reservoirs and intervene in existing fields with remedial sand control solutions; through extension of the viability of stand-alone screens, simplification of well construction or intervention and increase in productivity.
The observations made by the authors are supported by extensive laboratory testing. The resources provided in this paper will allow petroleum engineers to appropriately evaluate the potential benefits of utilizing ceramic sand screen technology in their completions.
The Hybrid Completion and Stimulation Technology Combining Sleeves with Bridge Plugs: A Case History in Ordos Basin, China
Authors: Tong Zheng , Ma Bing , Wei Ran , Liao Chenglong , Liu Shun , Huang Peng , Wang Xinzhong 
Published: October 2018

Abstract
Operator planned to develop the new low-permeable sandstone gas reservoir below the mature gas layer in Ordos basin. In terms of cost reduction the wellbore was designed to pass through the undeveloped resource locating in the upper mature reservoir to obtain dual-zone commingled production. According to the well logging, there was the indication of hole collapse, enlargement and an unforseen water bearing zone found in the deviated section locating in upper zone. Packers could fail in the irregular deviated wellbore.
Upon the modification of completion solution, the 4 1/2in open-hole packer-sleeve (OHPS) completion and fracturing system was deployed to treat the lower target zone. Top cementing operation using novel stage collar with swellable elements was performed to isolate the upper mature zone. "Plug and Perf" (PnP) via compact bridge plugs was carried out to enable efficient fracturing in deviated wellbore. The single-trip OHPS system employed water-swellable packers (WSPs) with corrugated packing element.
The WSP and compact bridge plug were successfully evaluated by bench test. In one gas well, the operator performed cementing job and the stage collar was opened by wiper plug once the tripping of the OHPS completion with five packers was made successfully. Three bridge plugs were pumped down to the target depth. Hydraulic fracturing operation was sequentially made with all packers and bridge plugs effectively set. It is shown from the field operation that the hybrid completion is able to meet the requirements of completion and stimulation in irregular wellbore with abnormal conditions for tight reservoirs.