|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
NextTier Oilfield Solutions announced today that it has recently started field testing electric fracturing pump technology developed by National Oilwell Varco (NOV). The two Houston-based energy companies are looking to the electric-based systems, also known as e-fleets, to improve efficiency and lower emissions at unconventional wellsites in the US. NextTier is currently using prototypes in the field and, if the pilot proves out, then the pressure pumper may end up purchasing the first e-fleet manufactured by NOV, the announcement said. NextTier added that its pending adoption of e-fleets would complement its dual-fuel fracturing fleets that can run on either diesel fuel or cleaner-burning natural gas. Like other commercial e-fleets, NOV’s system relies on gas turbines to generate power that is then used to drive the high-horsepower pumps.
After a year’s worth of hyperactive volatility, the outlook for oil production next year looks positively comatose. Both the big oil-producing countries in OPEC and the US shale producers appear likely to be delivering volumes in between the lows reached during the worst of the COVID-19 demand swoon and last year’s all-time high. With another surge in COVID-19 cases in progress worldwide, OPEC said it would stick with its current quotas because moves to slow the incidence of the infections are likely to stall demand growth, or worse. OPEC+, which includes Russia and other countries from outside the 13-member organization, predicted demand rising to 96.84 million B/D in the monthly report, down 80,000 B/D from its previous outlook, according to Reuters. Oil prices rose after that news but also likely benefitted from optimistic reports from two vaccine developers that said their clinical trial results to date indicate effectiveness.
SPE’s A Peer Apart award recognizes those dedicated individuals involved in the review of 100 or more papers for SPE’s peer-reviewed journals. Peer review is an essential part of scientific publishing and helps to ensure the information contained in a journal is well supported and clearly articulated. Volunteers who commit their time to review papers make substantial contributions to the technical excellence of our industry’s literature. Each year SPE typically has more than 1,400 individual reviewers submitting more than 3,500 reviews for SPE’s various journals. These committed volunteers come from a variety of backgrounds, including academia, service and operator companies, and consultancies from around the world.
Oklahoma City-based Gulfport Energy plans to shed nearly $1.25 billion in debt as it enters a court-supervised Chapter 11 bankruptcy process, according to a company statement on 14 November. Gulfport operates in the Oklahoma’s SCOOP and Ohio’s Utica Shale and as of the second quarter of this year was operating a single rig in each play. The company formed a new executive team in 2019 which was tasked with trimming costs and improving cash flow. However, Gulfport’s large debt load combined with long-term pipeline contracts meant it was on an unsustainable footing given current natural gas prices, ultimately driving its decision to enter bankruptcy, David Wood, president and CEO of Gulfport, said in the announcement. A prepackaged restructuring agreement was reached with most of the natural gas producer’s credit lenders and senior noteholders.
Tao, Liang (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Guo, Jianchun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Halifu, Mirinuer (Gubkin Russian State University of Oil and Gas, National Research University, Russia) | Zeng, Jie (The University of Western Australia) | Li, Ming (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Chen, Chi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Zhao, Yuhang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China)
Rock wettability is the key factor affecting the microscopic distribution of fluids in rock pores and the interaction between fluid and rock. However, the shale from the Longmaxi Formation (LF) in Sichuan Basin is rich in organic minerals, which make the quantitative test of mixed wettability of shale very difficult. In this study, firstly, the micro-pore structure of shale was quantitatively characterized by scanning electron microscope (SEM). Secondly, a new experimental apparatus for shale water spontaneous imbibition under the conditions of formation temperature and confining pressure was designed. Finally, the wettability index was proposed to quantitatively evaluate the water wettability, oil wettability and mixed wettability of shale. The experimental results shown that the organic-rich shale has complex mixed wettability, which was both water-wet and oil-wet. The contact angle of shale samples tested with distilled water were 13.5° and 70.5°, and the contact angles tested with kerosene were 0° and 9.6° at room temperature. The higher temperature the stronger shale hydrophilicity will be, and the water wettability of shale increases with the imbibition time.Therefore, a large amount of fracturing fluid spontaneously permeates into the shale micro-nano pores in the process of hydraulic fracturing, which is an important reason for the low flowback efficiency of shale gas wells. The research results provide effective guidance for the optimization of flowback system.
Ekundayo, Jamiu (Western Australian School of Mines, Curtin University and State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Rezaee, Reza (Western Australian School of Mines, Curtin University) | Fan, Chunyan (Western Australian School of Mines, Curtin University)
Gas desorption is one of the major gas transport mechanisms in shale gas reservoirs. However, its actual contribution to gas production is often masked by the indiscriminate use of adsorption-derived parameters for desorbed gas volumes during gas production calculations at reservoir conditions. Traditionally, it is believed that gas adsorption is fully reversible at the high-pressure, high-temperature conditions found in shale gas reservoirs.
In this paper, we studied methane adsorption and desorption isotherms using three shale samples at a reservoir temperature of 80oC. The resulting isotherms were modelled using the Langmuir model, following the conversion of measured excess amounts to absolute values. Lastly, a compositional 3D dual-porosity model was developed with CMG-GEM to test the effect of sorption hysteresis on gas production from a shale rock. For each sample, a base scenario, equivalent to a "zero-sorption" case, was compared against two other scenarios representing the two sorption processes.
For each sample, significant hysteresis was observed between the adsorption and desorption isotherms, with the desorption isotherms resulting in lower Langmuir parameters than the corresponding adsorption isotherms. For each process, Langmuir volumes showed a positive correlation with total organic carbon (TOC) contents. Also, the simulation results showed that gas production was lowest for the base case and highest for the adsorption case for each sample. This implies that neglecting the contribution of gas desorption can result in under-prediction of the gas production performances. On the other hand, using adsorption parameters to simulate desorbed gas volume could result in over-estimation of gas production performances.
Zeng, Lingping (Curtin University) | Iqbal, Muhammad Atif (Curtin University) | Reid, Nathan (CSIRO) | Lagat, Christopher (Curtin University) | Hossain, Md Mofazzal (Curtin University) | Saeedi, Ali (Curtin University) | Xie, Quan (Curtin University)
Megalitres of water with associated dissolved oxygen are injected into shale reservoirs during the hydraulic fracturing process. Pyrite oxidation, if it occurs
The spontaneous imbibition tests show that the salinity of fluids in ambient conditions is higher than the limited or vacuumed saturation fluids, confirming that pyrite oxidation generates H+ which would dissolve minerals such as calcite and dolomite. This result is also supported by the observed pH and the concentration of dissolved Ca2+. The fluid fully saturated with O2 has the lowest pH and highest Ca2+ compared to limited O2 saturation condition and degassed condition. Scanning electron microscopy analyses show that brine saturation barely affects the morphology and elemental distribution of pyrite at ambient conditions, suggesting that pyrite oxidation plays a minor role in fluid salinity. Geochemical modelling also indicates that although pyrite oxidation can slightly increase fluid salinity, the salinity increment is less than 5% of reported flowback water salinity, confirming that the dissolved O2 in hydraulic fracturing fluids has a minor effect on fluid-rock interaction thus the salinity increment. This work demonstrates that pyrite dissolution at lab-scale would overestimate the impact of fluid-shale interactions and calcite dissolution in reservoir conditions. We prove that pyrite dissolution in
The aim of this work is to study shale gas production subject to water blocking in compressible shale. Water blocking is a capillary pressure end-effect causing the wetting phase (e.g. water) to accumulate near the transition from a porous medium to an open medium; in this context, a transition from shale matrix to a hydraulic fracture. Shale is considered a tight porous medium with ultralow permeability, and hydraulic fracturing is essential to obtain economical production. Water is frequently used as a fracturing fluid, but its accumulation at the matrix end-face reduces the gas mobility and can lead to rapid decline of gas production rate.
The tight nature of the shale as a porous medium also introduces non-standard flow and storage mechanisms. This work develops a mathematical model that accounts for apparent permeability, compressibility of gas and shale, gas adsorption, Forchheimer gas flow, and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of the model at steady state production is explored to understand the impact of the various mechanisms.
Excessive greenhouse gas emission and natural gas shortage need to be tackled urgently nationally and globally. In this context, Carbon Capture Storage and Utilization (CCUS) has been proposed to: (1) mitigate the global warming by removing carbon from the atmosphere and, at the same time, (2) create value/reduce the cost by utilizing them for production. CO2 Storage with Enhanced Gas Recovery (CS-EGR) is well fit for the purpose of CCUS. This paper analyses the feasibility of CS-EGR in Australia by characterizing reservoir rock and fluid properties from both conventional and unconventional gas reservoirs, and by modelling the process of CO2 injection, gas production, and CO2 storage.
This paper discusses technical aspects of injection and storage of CO2 and the behaviours of CO2 and methane together with enhancement of gas production. Although both conventional and unconventional gas reservoirs are covered, the emphasis is given to the unconventional gas. CO2 is more preferentially adsorbed to shale or coal than CH4, so the injected CO2 will displace CH4 which then can be recovered. It is also miscible with natural gas and is good for re-pressurizing reservoir. However, these processes are highly influenced by many factors, such as reservoir temperature and pressure, total organic content (TOC), porosity, permeability, pore size (distribution), injection operation, mineralogy, fracture, fluids and so on. Numerical simulation is a perfect tool to study how different parameters interact with each other and eventually affect the efficiency of CS-EGR.
The authors undertake geological and petrophysical characterization of target formations in Australia. It is then followed by numerical modelling which takes consideration of reservoir characterization data and interaction between CO2, CH4, H2O and rock. The sensitivity analysis investigates the performance of CS-EGR at different scenarios and identifies the critical factors. It is worthwhile to mention that two gas injection methods, gas flooding, huff'n'puff, (or cyclic gas injection), are studied and compared.
Based on previous studies, this paper moves a step further by: (1) incorporating reservoir characterization data from Australia gas field in numerical modelling and exploring the feasibility of CO2 Storage with Enhanced Gas Recovery in Australia; (2) investigating both unconventional gas reservoirs and conventional reservoirs and makes a comparison between them; (3) comparing two injection methods for all different reservoirs; (4) performing sensitive analysis of multiple parameters identified from analysis and literature. CS-EGR is promising in achieving "net-zero emission" for Australia.
In 2012, the International Energy Agency (IEA) released the ‘Golden Rules for a Golden Age of Gas’ - a set of best practice guidelines for unconventional gas development designed to address key environmental and social risks and gain public acceptance of the industry. This study sought primarily to understand the extent to which the experience of developing a large-scale coal seam gas (CSG) to liquefied natural gas (LNG) industry in Queensland, Australia was seen to have aligned with the Golden Rules, and how well the Golden Rules were seen to contribute to public acceptance of the industry.
An evaluation tool was developed where the seven Golden Rules and their subclauses were adopted as criteria in a scorecard approach. We conducted interviews with 32 senior people who had been directly involved in the development of the CSG industry in Queensland, from local, state and federal governments, gas companies, host communities as well as researchers and consultant ‘experts’.
The Queensland experience of unconventional gas development rated reasonably well in relation to the Golden Rules, with scores of three or higher out of five for four of the seven rule categories. Across all the Golden Rules, industry performance scored more highly than the effectiveness of the policy/regulatory environment, highlighting the complex and sometimes conflicted roles of governments in developing a new industry. The rules addressing baseline measurement, full disclosure and engagement were seen as most important for public acceptance.
This study developed a new tool to evaluate perceived social and environmental performance of industry and effectiveness of governance in unconventional gas development applicable across different jurisdictional contexts. This application suggests that baseline measurements, open disclosure and public engagement should be the focus for building public acceptance. For new gas developments, these findings highlight the importance of having a robust regulatory environment in place that can coordinate activities and manage cumulative impacts.