|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
This paper presents novel approaches to carbon abatement using petroleum that have a strong chance to succeed in fulfilling technological and economic goals. The complete paper describes an advanced Rankine cycle process-based system that converts waste heat into usable electrical power to improve the efficiency of gas-compression stations on gas-production platforms and pipelines. Despite the global downturn, the long-term transition to net zero presents a major opportunity to create new multibillion industries based around the North Sea. Cross-sector collaboration and major state/private sector intervention, together with strong leadership, will be key. What the industry needs at this stage is a willingness to work together, share best practices, conduct innovative research, and focus on disruptive technologies that lower cost of capture and make our operations more sustainable.
Phase 1 is expected to be operational in 2024. BP says it is firmly committed to achieving the ambitious target of net-zero greenhouse gas emissions over the next 30 years—even if that means producing less oil and gas. Amid weakening confidence and volatile market conditions, greater efficiencies and decarbonization are at the center of the industry’s agenda. The companies will focus on research and development to reduce CO2 emissions and promote the circular economy. A new joint study will test the economic viability of taking CO2 from a cement plant and giving it to an oil company to pump underground.
BP says it is firmly committed to achieving the ambitious target of net-zero greenhouse gas emissions over the next 30 years—even if that means producing less oil and gas. Amid weakening confidence and volatile market conditions, greater efficiencies and decarbonization are at the center of the industry’s agenda. The companies will focus on research and development to reduce CO2 emissions and promote the circular economy. A new joint study will test the economic viability of taking CO2 from a cement plant and giving it to an oil company to pump underground. The Spanish oil and gas company says existing or foreseeable technologies will achieve at least 70% of its ambitious plan to shrink its carbon footprint.
In some reservoir applications, seismic data are acquired with downhole sources and receivers. If the receiver is stationed at various depth levels in a well and the source remains on the surface, the measurement is called vertical seismic profiling (VSP). This technique produces a high-resolution, 2D image that begins at the receiver well and extends a short distance (a few tens of meters or a few hundred meters, depending on the source offset distance) toward the source station. This image, a 2D profile restricted to the vertical plane passing through the source and receiver coordinates, is useful in tying seismic responses to subsurface geologic and engineering control. If the source is deployed at various depth levels in one well and the receiver is placed at several depth stations in a second well, the measurement is called crosswell seismic profiling (CSP). Images made from CSP data have the best spatial resolution of any seismic measurement used in reservoir characterization because a wide range of frequencies is recorded.
Several approaches that use the activity coefficient model assume the oil and asphaltene as two pseudocomponents: one component representing the deasphalted oil and the other the asphaltenes. Andersen and Speight provided a review of activity models in this category. Other approaches represent the precipitate as a multicomponent solid. Chung, Yarranton and Masliyah, and Zhou et al. gave detailed descriptions of these models. The solubility model used most in the literature is the Flory-Huggins solubility model introduced by Hirschberg et al. Vapor/liquid equilibrium calculations with the Soave-Redlich-Kwong EOS are performed to split the petroleum mixture into a liquid phase and a vapor phase.
This paper seeks answers, through a'philosophical' approach, to the questions of whether enhanced oil recovery projects are purely driven by economic restrictions (i.e. oil prices) or if there are still technical issues to be considered, making companies refrain from enhanced oil recovery (EOR) applications. Another way of approaching these questions is to ask why some EOR projects are successful and long-lasting regardless of substantial fluctuations in oil prices. To find solid answers to these two, by'philosophical' reasoning, further questions were raised including: (1) has sufficient attention been given to the'cheapest' EOR methods such as air and microbial injection, (2) why are we afraid of the most expensive miscible processes that yield high recoveries in the long run, or (3) why is the incubation period (research to field) of EOR projects so lengthy? After a detailed analysis using sustainable EOR example cases and identifying the myths and facts about EOR, both answers to these questions and supportive data were sought. Premises were listed as outcomes to be considered in the decision making and development of EOR projects. Examples of said considerations include: (1) Every EOR process is case-specific and analogies are difficult to make, hence we still need serious efforts for project design and research for specific processes and technologies, (2) discontinuity in fundamental and case-specific research has been one of the essential reasons preventing the continuity of the projects rather than drops in oil prices, and (3) any EOR project can be made economical, if technical success is proven, through proper optimization methods and continuous project monitoring whilst considering the minimal profit that the company can tolerate. Finally, through the'philosophical' reasoning approach and using worldwide successful EOR cases, the following three parameters were found to be the most important factors in running successful EOR applications, regardless of oil prices and risky investment costs, to extend the life span of the reservoir and warrant both short and long-term profit: (1) Proper technical design and implementation of the selected EOR method through continuous monitoring and re-engineering the project (how to apply more than what to apply), (2) good reservoir characterization and geological descriptions and their effect on the mechanics of the EOR process, and (3) paying attention to experience and expertise (human factor). It is believed that the systematic analysis and philosophical approach followed in this paper and the outcome will provide proper guidance to EOR projects for upcoming decades. 2 SPE-196362-MS
Song, Zhaojie (China University of Petroleum, Beijing) | Li, Yuzhen (China University of Petroleum, Beijing) | Song, Yilei (China University of Petroleum, Beijing) | Bai, Baojun (Missouri University of Science and Technology) | Hou, Jirui (China University of Petroleum, Beijing) | Song, Kaoping (China University of Petroleum, Beijing) | Jiang, Ajiao (China University of Petroleum, Beijing) | Su, Shan (China University of Petroleum, Beijing)
Primary oil recovery remains less than 10% in tight oil reservoirs, even after expensive multistage horizontal well hydraulic fracturing stimulation. Substantial experiments and pilot tests have been performed to investigate CO2-EOR potential in tight reservoirs; however, some results conflict with each other. The objective of this paper is to diagnose how these conflicting results occurred and to identify a way to narrow the gap between experimental results and field performance through a comprehensive literature review and data analysis.
Peer-reviewed journal papers, technical reports, and SPE publications were collected, and three key steps were taken to reach our goal. First, rock and fluid properties of tight reservoirs in North America and China were compared, and their potential effect on tight oil production was analyzed. Afterward, based on published experimental studies and simulation works, the CO2-EOR mechanisms were discussed, including molecular diffusion, CO2-oil interaction considering nanopore confinement, and CO2-fluid-rock minerals interaction. Subsequently, pilot projects were examined to understand the gap between laboratory works and field tests, and the challenges faced in China's tight oil exploitation were rigorously analyzed.
Compared with Bakken and Eagle Ford formation, China's tight oil reservoirs feature higher mud content and oil viscosity while they have a lower brittleness index and formation pressure, leading to confined stimulated reservoir volume and further limited CO2-oil contact. The effect of CO2 molecular diffusion was relatively exaggerated in experimental results, which could be attributed to the dual restrictions of exposure time and oil-CO2 area in field scale. Numerical modeling showed that the improved phase properties in nanopores led to enhanced oil recovery. The development of nano-scale chips withholding high pressure/temperature may advance the experimental study on nano-confinement's effect. Oil recovery can be further enhanced through wettability alteration due to CO2 adsorption on nanopores and reaction with rock minerals. CO2 huff-n-puff operations were more commonly applied in North America than China, and the huff time is in the order of 10 days, but the soaking time is less. Conformance control was essential during CO2 flooding in order to delay gas breakthrough and promote CO2-oil interaction. There is less than 5% of tight oil reserve surrounded by CO2 reservoirs in China, limiting the application of CO2-EOR technologies. An economic incentive from the government is necessary to consider the application of CO2 from power plants, refineries, etc.
This work provides an explanation of conflicting results from different research methods and pilot tests, and helps researchers and oil operators understand where and when the CO2-EOR can be best applied in unconventional reservoirs. New directions for future work on CO2-EOR in tight formations are also recommended.
As the price of oil reached approximately USD 147 per barrel on 3 July 2008, an increasing number of mature oil fields became attractive for redevelopment. On the fifth anniversary of the highest oil price yet attained TWA asked,"What defines a mature oil field?" According to Paul Bondor, 2010–11 SPE Distinguished Lecturer, retired from Shell after 35 years of technical and supervisory service, "a mature oil field is an oil field that is considered fully developed. There may be infill opportunities but in general the field-development plan has been executed. "There may or may not be secondary recovery with gas or water injection.
Ren, Bo (The University of Texas at Austin) | Male, Frank (The University of Texas at Austin) | Wang, Yanyong (The University of Texas at Austin) | Baqués, Vinyet (The University of Texas at Austin) | Duncan, Ian (The University of Texas at Austin) | Lake, Larry (The University of Texas at Austin)
The objectives of this work are to understand the characteristics of oil saturation in residual oil zones (ROZs) and to optimize water alternating gas (WAG) injection strategies. ROZs occur in the Permian Basin and elsewhere, and operators are using CO2 injection for enhanced oil recovery (EOR) in these zones. ROZs are thought to be formed by the flushing effect of regional aquifer flow acting over geological time. Both the magnitude of oil saturation and the spatial distribution of oil differ from water-flooded main pay zones (MPZs).
We conducted flow simulations of CO2 injection into both synthetic and realistic geologic reservoirs to find the optimal injection strategies for several scenarios. These simulations of CO2 injection follow either man-made waterflooding or long-term natural waterflooding. We examined the effects of CO2 injection rates, well patterns, reservoir heterogeneity, and permeability anisotropy on optimal WAG ratios. Optimal is defined as being at minimal net CO2 utilization ratios or maximal oil production rates).
Simulations of CO2 EOR show that the optimal WAG ratio for the ROZs is less than 1 (ratio of injected water and CO2 in reservoir volumes), and it depends, but in qualitatively different ways, upon the well pattern and reservoir heterogeneity. The optimal WAG ratio tends to increase with changing from inverted 9-spot (80-acres) to inverted 5-spot (40-acre) or increasing reservoir heterogeneity. The ratios for ROZs are consistently less than those observed in the same geologic models experiencing CO2 injection after traditional (man-made) waterflooding. This is because the water saturation caused by slow regional aquifer flow (~1ft/yr) differs from that created by traditional waterflooding. In ROZs, water prevails almost everywhere and thus it is less needed to ease CO2 channeling as compared to MPZs.
This work demonstrates that optimal WAG ratios for oil production in ROZs are different from those in traditional MPZs because of oil saturation differences. Thus, commingled CO2 injection into both zones or directly copying WAG injection designs from MPZs to ROZs might not optimize production.
Ketineni, Sarath Pavan (Chevron Corporation) | Tan, Yunhui (Chevron Corporation) | Hoffman, Katrina L. (Chevron Corporation) | Jones, Matthew (Chevron Corporation) | Ghoraishy, Mojtaba (Chevron Corporation)
Demonstrating the viability of multistage hydraulic fractured horizontal wells to unlock otherwise trapped resources is presented through a case study on Rangely. A combination of high-fidelity reservoir models was employed for accurate forecasts and evaluation of hydraulically fractured horizontal wells to improve resources in this mature conventional oil field with ongoing pressure support and tertiary recovery operations. The modeling techniques used in this method can be extended to other mature oil fields to unlock bypassed oil setting a precedent to re-evaluate mature oil fields with the new unconventional completion technologies.
The Rangely Weber Sand Unit is an Eolian sandstone depositional system consisting of 2 billion bbls of oil in place. The Weber Formation is Pennsylvanian to Permian in age, and typically consists of fine-grained and cross bedded calcareous sandstones. Structurally oil is trapped in an anticline with varying dip angles on the flanks. The oil production from this reservoir was managed through primary depletion for the first two decades of production followed by secondary recovery via water flood and concluding through water alternating CO2 injection (WAG) over the last three decades. Due to the heterogeneity in depositional environment, the recovery factors have been low in the eastern end of the field. The east end of the field has relatively lower permeability and lower porosity compared to the rest of the field. A modeling workflow is presented to assist with evaluation and optimization of hydraulically fractured horizontal infill wells to recover bypassed oil in the eastern end of the Rangely field.
A full fidelity static model was built based on dense, high quality well control data. A sector model was history matched, and then used to update pressure, saturations, and stress distribution to present day. The history matched model was subsequently used to evaluate horizontal well performance and hydraulic fracturing completion options to overcome these heterogeneities and improve recovery from a lower quality reservoir.
Completions optimization opportunities were focused on fracture geometry, incremental Estimated Ultimate Recovery (EUR), and economics. Sensitivity studies demonstrated that an optimal balance of cost and recovery is found at the low end of fracture volumes and wider perforation cluster spacing. Forecasting runs show incremental economic recovery which otherwise could not have been recovered through ongoing WAG operations.