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Brinkley, Kourtney (Devon Energy) | Ingle, Trevor (Devon Energy) | Haffener, Jackson (Devon Energy) | Chapman, Philip (Devon Energy) | Baker, Scott (Devon Energy) | Hart, Eric (Devon Energy) | Haustveit, Kyle (Devon Energy) | Roberts, Jon (Devon Energy)
Abstract This case study details the use of Sealed Wellbore Pressure Monitoring (SWPM) to improve the characterization of fracture geometry and propagation during stimulation of inter-connected stacked pay in the South Texas Eagle Ford Shale. The SWPM workflow utilizes surface pressure gauges to detect hydraulically induced fracture arrivals athorizontal monitor locations adjacent to the stimulated wellbore (Haustveit et al. 2020). A stacked and staggered development in Dewitt County provided the opportunity to jointly evaluateprimary completion and recompletion efforts spanning three reservoir target intervals. Fivemonitor wells at varying distances across the unit were employed for SWPM during the stimulation of four wells. An operational overview, analysis of techniques, correlation with seismic attributes, image log interpretations, and fracture model calibration are provided. Outputs from this workflow allow for a refined analysis ofthe overall completion strategy. The high-density, five well monitor array recorded a total of 160 fracture arrivals at varying vertical and lateral distances, with far-field fracture arrivalsprovidingsignificant insight into propagation rates and geometry. Apronounced trend occurred in both arrival frequency and volumes pumped as monitor locations increased in distance from the treatment well. Specific to target zone isolation, it was identified that traversing vertically in section through a high stress interval yielded a 30% reduction inarrival frequency. An indirect relationship between horizontal distance and arrival frequency was also observed when monitoring from the same interval. A decrease in fracture arrivals from 70% down to 8% was realized as offset distance increased from 120 to 1,700 ft. The results from this study have proven to be instrumental in guiding interdisciplinary discussion. Assessing fracture geometry and propagation during stimulation, particularly in the co-development of a stacked pay reservoir, is paramount to the determination of proper completion volume, perforation design, and well spacing. Leveraging the observations of SWPM ultimately provides greater confidence in field development strategy and economic optimization.
The success of any digital oilfield project is predicated on the quality of the data structure, acquisition, communication, validation, storage, retrieval, and provenance of the data. Therefore, the mission of the digital oilfield architect is clear: Deliver the right data to the right users at the right time. This task is becoming more difficult because of the sheer variety of sensors, the multitude of data formats, challenges with data communication and synchronization, and the potentially large volume of data produced. While the advent of data analytics has increased the importance of designing fast and efficient data management systems, it is a multifaceted minefield to gather and process data to ensure production is optimized and risk is minimized in both conventional and unconventional operating environments. The existing proliferation of sensors and the projected growth rate of new sensor technology is expected to reach around $30.57 billion by 2026, a boost of 24.65% CAGR (compound annual growth rate), according to market intelligence.
For the oil and gas industry, the last decade (2003 to 2013) has been one of "resilience, extraordinary innovation, and, despite setbacks, significant gains in safety and environmental conformance," according to Paal Kibsbaard, chief executive officer of Schlumberger, in his report "A Decade of Upstream Technology Innovation" included in the World Petroleum Council's 80th Anniversary Edition report (2013). The industry remains strong, after sustaining humanity's supply of oil and gas and thereby meeting more than half the global energy needs throughout the decade. In the June 2010 issue of the Journal of Petroleum Technology, Behrooz Fattahi, 2010 SPE president, said the industry has been focusing on the concept of sustainability or its components "for a long time, but under different descriptive terms--optimizing production, maximizing reserves, reducing cost, cutting waste, increasing efficiency, optimizing processes, minimizing footprint, maximizing safety, reducing environmental impact, and increasing corporate social responsibility." Sensitivity to all these factors is required when looking back on the industry's last 10 years and looking ahead to the next 10 years. The oil and gas industry has always been a risky business for many reasons--from geophysics to geopolitics.
The subsea market in 2019 will experience year-on-year growth for the first time since 2014, but the positive outlook is vulnerable to any significant decline in oil prices over the next few years. Rystad Energy expects the subsea market to thrive during the coming years, but market growth will be at risk if the oil price falls to $50 per barrel. An analysis of the outlook for global subsea segments in the coming years forecasts that development this year is essentially locked in with brownfield opportunities and already-sanctioned projects--but the oil price will dictate growth moving forward. In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel.
History of SPE In 1957, the organization was officially founded as SPE, a constituent society of AIME. SPE became a separately incorporated organization in 1985. Our history begins within the American Institute of Mining Engineers (AIME). AIME was founded in 1871 in Pennsylvania, USA, to advance the production of metals, minerals, and energy resources through the application of engineering. In 1913, a standing committee on oil and gas was created within AIME and proved to be the genesis of SPE. The Oil and Gas Committee of AIME soon evolved into the Petroleum Division of AIME as membership grew and as interest among the members was more clearly delineated among the mining, metallurgical, and petroleum specializations.
Sakurai, Shunsuke (University of Western Australia) | Norris, Bruce (University of Western Australia) | Hoskin, Ben (Oilfield Technologies Pty. Ltd.) | Choi, Joel (Oilfield Technologies Pty. Ltd.) | Nonoue, Tomoya (Japan Oil, Gas and Metals National Corporation, currently, JGC Corporation) | Eric, May (University of Western Australia) | Aman, Zachary (University of Western Australia)
Natural gas hydrate has attracted interest as an energy resource capable of meeting the expected growth in global energy demand. Several key issues remain to be tackled to enable commercial production, one of which is gas hydrate re-association in production lines, where significant volumes of water are co-produced with free gas. To predict this behavior, we introduce a model and simulation tool tailored towards hydrate growth in water-dominant turbulent flow.
We have produced a model to predict the growth rate of hydrate in water dominant systems, integrated into an in-house pseudo-steady-state multiphase flow simulator, named HyFAST. This is a mass transfer limited model where the growth rate is limited by the dissolution of guest gas molecules into the water-continuous phase. It considers the effect of interfacial gas-water bubble surface area, the degree of turbulence on mixing, and changes in bulk viscosity caused by hydrate particle formation. The tool is deployed to estimate the hydrate volume formed in production lines during the second offshore methane hydrate production test in Japan.
Initially, the model was validated in an experimental study against flowloop data, where, at worst, model predictions showed order of magnitude agreement with experimental growth rates; following this the model was integrated into an overall flow simulation tool used for larger scale predictions. The offshore production test was designed to use two separate lines to produce gas and water, however, some gas was entrained into the water production line, posing a risk of re-association. As such, our primary focus was on this water production line, approximately 1 km in length, rather than the gas production line, which generally remained outside the hydrate stability region. Our simulation predictions showed that the hydrate volume in the water production line was less than 5 vol%. Coupled with flowloop data which showed that blockages did not occur in similar systems up to 20 vol% hydrate, this suggests there was not a significant hydrate blockage likelihood in the offshore production test. These initial results suggest that the model may scale well from lab to field, and that such simulation tools can prove useful in discussing the consequences of hydrate re-association.
A new model and simulation tool were developed to predict the rate and extent of hydrate growth in water-dominant flow. These were used to predict hydrate formation in both flowloop experiments and actual production lines. The validation results showed that the approach may prove useful in evaluating hydrate blockage propensity in future gas hydrate production.
Abstract Calcium carbonate (CaCO3) scale formation in production wells and process systems is a well-known challenge in the oil and gas industry. Various strategies are selected to prevent scale formation (proactive, e.g. by scale inhibitors) or to remove scale when it has formed (reactive, e.g. by acid treatment), depending on the severity of the problem and the complexity of the production system. Lack of access for remedial actions may be a limiting factor in subsea and unmanned installations and scaling may represent a larger risk of production losses or system failures. The scale management strategy and design of new wells during field development are based on thermodynamic calculations, kinetic studies and field observations. Experience has shown that wells with high temperature and high pressure drops are more prone to downhole calcium carbonate scaling. Field experience has been collected and systemized based on operations of oil and gas-condensate fields in the North Sea and Norwegian Sea. The observations have been compared to thermodynamic calculations and aligned to kinetic modelling, defining the critical saturation ratio (SRCaCO3) for scaling. The result is a graphic which has proved to be a powerful tool in planning of new wells and is described in this paper. The Oseberg field in the North Sea is producing from oil and gas-condensate wells at various reservoir temperatures (98-128°C). The field comprises platform and subsea production systems and one unmanned wellhead platform. Seawater has been injected for pressure support in some areas, while gas injection or depletion are the driving forces in other segments. The CaCO3 scale potential and management strategy have been evaluated for new wells in a field life perspective. Risk of production losses and maximizing cost benefit are key selection criteria, and the variety of wells requires individual solutions. The paper discusses the need for downhole continuous injection of scale inhibitor, compared to batch scale inhibitor squeeze treatments and/or acid treatments. Guidelines for optimum operation of these wells to avoid scaling are presented.
May, Eric F. (University of Western Australia) | Metaxas, Peter J. (University of Western Australia) | Lim, Vincent W. S. (University of Western Australia) | Jeong, Kwanghee (University of Western Australia) | Norris, Bruce W. (University of Western Australia) | Kuteyi, Temiloluwa O. (University of Western Australia) | Stanwix, Paul L. (University of Western Australia) | Johns, Michael L. (University of Western Australia) | Aman, Zachary M. (University of Western Australia)
Abstract Quantitative prediction of gas hydrate formation risk is critical for the successful implementation of risk-based approaches to hydrate management in subsea production. Here we use a high pressure, stirred, automated lag-time apparatus and a high pressure acoustic levitator to experimentally obtain smooth probability distributions describing stochastic hydrate formation. Robust, repeatable hydrate nucleation and growth rate probability distributions as a function of induction time and subcooling are measured for various gases, shear rates and inhibitor dosages in systems with interfacial areas ranging from (0.1 to 60) cm. The results reveal that new engineering models can be used to reliably predict hydrate formation probability. Importantly these new models have solid theoretical foundations which enables them to be generalized with confidence to industrial systems.
Primary cementing is a crucial task in the completion of oil and gas wells, as it is potentially meant to provide zonal isolation, and prevent uncontrolled flows and environmental hazards. Much research has been conducted to find the key techniques for obtaining the maximum displacement efficiency during cementing operations. Yet, it appears that the industry could benefit from more investigations on the complications involved in displacement processes.
In this work, a methodology is proposed in an attempt to obtain qualitative and quantitative predictions of displacement efficiency. This method, which appears to complement previously existing methods, introduces a combined analysis of instability of the interface between the two fluids with an analytical solution of fluid displacement flow in eccentric annuli. The analytical solution enables the time-dependent calculation of interface location and provides a quantitative judgement on the volume fraction of the displaced fluid left in the annular space. On the other hand, the instability models provide an insight on the degree of cement contamination, and guidelines on how to minimize the amount of inter-mixing.
The proposed approach was implemented for several displacement cases and the results were evaluated by both Computational Fluid Dynamics (CFD) simulations and experimental tests. Instability of the interface in all the cases was studied and the analysis provided more in-depth understanding of the effect of different parameters on displacement efficiency. Considering that in the existing analytical models, including the one presented in this work, the interface between the two fluids is supposed to be sharp, the calculated volume fraction of displacing fluid can be not necessarily a proper representative of the real displacement efficiency. It was observed that there can exist cases where the volume fraction of the displacing fluid did not necessarily indicate an inefficient displacement, whereas the instability analysis suggested that the corresponding design had to be avoided. This was also validated by CFD simulations. Moreover, the instability model can provide more information about the critical values of design parameters and propose optimized designs for the improvement of displacement efficiency.
The present work provides a versatile tool that enables quantitative determination of displacement efficiency, along with an enhanced judgement on the amount of inter-fluid mixing and cement contamination. The novel approach of coupling the instability analysis with displacement flow calculation not only offers improvements on displacement designs, but also assists to avoid any undesirable outcomes caused by ineffective cement placement.
Abstract The oil and gas supply and demand pattern, "two supply belts, three consumption centers", remains basically unchanged. However, the unconventionaloil and gas output in the United States continues to grow rapidly, resulting in an oversupply of oil and gas around the world, which has an impact on the international oil price, so there is a profound impact on global exploration and development under the background of the low oil price. First, OPEC and Russia continued to cut supply, while the production growth of unconventional oil and gas in the United States realized its oil and gas exports, driving the change of the oil and gas geopolitical structure. Second, the global demand for crude oil grew moderately, slower than that for natural gas. Third, exploration investment plummeted under the low oil price, while newly proven reserves around the world continued to decrease. Fourth, development investment returned to low-cost and high-quality mature oil fields, while new capacity was reduced. However, with the gradual recovery of the international oil price in the future, the global oil and gas development will show a new trend. It is expected that the upstream construction costs will rise, with onshore costs recovering faster than that of the sea areas. If the global exploration and development investment continues to decline in the future, the global oil and gas will be in short supply in the next three to five years, which will once again affect the current tight balance between oil and gas supply and demand. Therefore, it is expected that both the oil price and the exploration and development investment will increase in 2018, and the game between OPEC and the United States will continue.