Carbon dioxide (CO2) injection has recently been applied as an enhanced oil recovery (EOR) method to increase oil recovery from unconventional shale reservoirs. Many interactions will impact the success or failure of this EOR method. This research experimentally investigates the impact of two of these interactions, including asphaltene pore plugging and CO2 adsorption, on the success of CO2 EOR in unconventional shale reservoirs. Two sets of experiments were designed to study the asphaltene pore plugging and CO2 adsorption. The impact of varying CO2 injection pressure, temperature, oil viscosity, and filter membrane pore size on asphaltene pore plugging was investigated. Pertaining to the adsorption experiments, the impact of varying CO2 injection pressure, temperature, and shale particle size was investigated. Asphaltene pore plugging was found to be extremely severe especially in the smaller pore sizes, which indicates that asphaltene poses a serious problem when producing from unconventional nanopores. As the oil viscosity decreased, the asphaltene concentration in the oil decreased as well which made the asphaltene pore plugging less severe in the lower viscosity oils. The thermodynamic conditions, including pressure and temperature, also had a strong impact on asphaltene stability and pore plugging. When undergoing the CO2 adsorption experiments, it was found that increasing the CO2 injection pressure resulted in an increase in adsorption capacity to a certain limit beyond which no further adsorption will be possible. Increasing the temperature resulted in the CO2 molecules becoming highly active which in turn resulted in a decrease in the adsorption capacity significantly. Since experiments were conducted using shale particles, as opposed to an actual shale core, it was important to investigate the accuracy of the results by varying the shale particle size. It was found that as long as the void space volume was measured accurately using helium, the shale particle size had a negligible effect on the adsorption values. This research systematically investigates the impact of two significant interactions on the success of CO2 injection in unconventional shale reservoirs, and studies the impact of several factors within these interactions to determine the extent to which they may influence the success of this EOR method.
The 2016 SPE International Student Paper Contest was held at the SPE Annual Technical Conference and Exhibition (ATCE) in Dubai and the following papers are announced winners. These papers will be published in the ATCE conference proceedings and on OnePetro, a multisociety technical library for the oil and gas exploration and production industry. Winners of the 14 SPE Regional Student Paper Contests from each division competed for the international recognition. "Wellbore Stability Analysis Based on Sensitivity and Uncertainty Analysis" by Fernando Antonio Plazas Niño, Universidad Industrial de Santander
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Hydrocarbon miscible flooding for oil recovery in low permeability reservoirs has proved to be promising in the past few years. Mobility control in this process is crucial for commercial vitality where severe reservoir heterogeneity can cause very poor sweep efficiency. Aqueous foam has been proved effective for conformance control in heterogeneous reservoirs. However, water injection required to sustain foam performance can be challenging in water sensitive tight oil formations. This study introduced a new concept of non-aqueous foam-assisted hydrocarbon miscible flooding in heterogeneous tight oil formations. This process involves the injection of Natural Gas Liquids Mixture (NGLM) as a raw mixture of natural gas liquids, which has been becoming more available with the increase in wet gas, shale plays over the last decade. The injection of non-condensable gas (i.e., nitrogen or methane) and NGLM with a foam stabilizing additive may provide a recovery scheme with both strong displacement and sweep efficiency. The foaming ability of a hydrocarbon liquid and how such non-aqueous foam influences miscible displacement are the main focuses of this study.
n-Pentane was used as a simple NGLM model for the low-pressure foam stability tests. Transient foam propagation and its rheological behavior were directly visualized and characterized based on the apparent gas (nitrogen) viscosity associated with foam texture (i.e., bubble density) and fluid saturations. The impact of foam propagation on miscible displacement efficiency was evaluated by comparing oil recovery factors for different degrees of in-situ foaming.
For the injection of a liquid pentane slug followed by a gas drive, the displacement of oil became unstable as nitrogen fingered through the solvent-oil mixing zone, resulting in a relatively high residual (solvent and oil) saturation. However, gas fingering was significantly hindered as the solvent slug was injected with a dissolved foaming agent. Direct visualization of dynamic fluid distribution during the flooding clearly indicates that the improved recovery could be attributed to the generation and propagation of hydrocarbon foam in the swept zone, which provided essential flow resistance in this zone for better displacement stability. To investigate the effect of pre-injected gas or naturally occurring gas in the reservoir on flow behavior and sweep efficiency, a slug of gas was injected and chased by liquid pentane. Delayed pentane breakthrough and better sweep efficiency were observed in the presence of foam due to the reduced liquid phase mobility in preferential flow paths and the diversion of solvent into small pores by the trapped gas at the displacing front. Furthermore, it was possible to obtain stable foam flow with an apparent viscosity of 20 times greater than the solvent viscosity.
This work provides a pioneer study in applying non-aqueous foam for conformance control in hydrocarbon miscible flooding in tight oil formations. The pore-scale visualization provides a better understanding of the mechanisms of non-aqueous foam generation and destruction in porous media, which have been rarely found in the literature. Furthermore, the experimental results demonstrate that the sweep efficiency and the recovery factor of miscible injection can be significantly enhanced by non-aqueous foam.
A significant amount of oil is trapped within organic nanopores of shale that cannot be recovered by primary production from these resources. The main reason for the large unrecovered oil volumes in shale reservoirs is the presence of nanoscale pore sizes, which leads to extremely small permeability values, and trapping of hydrocarbons in the adsorbed state on the surfaces the pores. For these resources, effective enhanced oil recovery (EOR) techniques are required to displace oil from nanoscale shale matrix. Due to small permeability, it is difficult, if not impossible, to conduct water and chemical flooding in these resources. Maintaining a stable flood front in immiscible gas flooding is challenging due to the severe fingering phenomenon cause by the naturally fractured nature of these formations. Gas huff-n-puff becomes the most suitable EOR method in shale reservoir development. For decades, carbon dioxide EOR techniques have been successfully applied in conventional reservoirs to improve oil production. In this work, the physics behind CO2 injection into organic nanopores of shale is investigated using molecular dynamics simulations. A 3D kerogen nanochannel, based on the kerogen unit molecules prepared by Ungerer et al. (2014), is created along with a synthetic oil mixture created based on the experimental study of phase behavior of petroleum mixtures performed by Turek et al. (1984). Supercritical CO2 (sCO2) is then injected into the channel at different pressures and oil recovery factors are computed. Results of this study demonstrates that the C7+ component of the oil sample have higher adsorption tendency than lighter hydrocarbon components. Furthermore, it is shown that sCO2 could potentially produce oil, especially lighter components, from organic matters in shale oil reservoirs. It is observed that as sCO2 injection pressure increases, the required soaking time for maximum process performance increases.
Trapped within organic shale matrix, there is a large amount of unrecovered oil content that cannot be removed through primary depletion due to the nanoscale pore size and extremely low permeability values for unconventional reservoirs. Due to these microscopic pore sizes and low permeability values, effective and efficient enhanced oil recovery (EOR) techniques are vital to increasing the oil recovery factor (Kazemi and Takbiri-Borujeni, 2015). Given the properties of these unconventional shale reservoirs, water and chemical flooding become very difficult to perform. Severe fingering effects also take place throughout the fractures within the matrix, adding to the difficulty of gas flooding procedures. With these challenges in mind, gas huff-n-puff becomes the most effective method of EOR for unconventional shale formations. In conventional reservoirs, CO2 gas injection has been a very successful method for increasing the oil production. Given the great success of CO2 gas injection in conventional reservoirs, recent studies have also shown the effectiveness CO2 injection throughout unconventional reservoirs because CO2 has a very high adsorption affinity to the walls of the porous organic matter found within shale gas reservoirs (Jin et al., 2017). By changing the fluid-fluid, rock-fluid, and gaseous interactions by CO2 injection, larger amounts of hydrocarbons can be produced.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Produced water is treated in offshore operations for overboard disposal or injection into a disposal well. Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Surface water is treated offshore for liquid injection and onshore for liquid- or steam-injection purposes. In all instances, the surface water must be cleaned of dispersed and dissolved solids to a level suitable for reservoir or steam-generation purposes.
The Society of Petroleum Engineers-Permian Basin Section (SPE) is collaborating with University of Texas Permian Basin's (UTPB) STEM Academy and Communities in Schools Permian Basin (CISPB) to kick-off the new school year with energy education! All oil and gas professionals and students are invited to participate in energy4me, SPE's initiative to educate K-12th graders about the importance of energy and practical STEM applications in the energy industry. Energy4me has lesson plans available for volunteers so they can immediately utilize and apply them for interactive activities and classroom discussions. The kickoff event is meant to benefit elementary to high school students of the UTPB STEM Academy and CISPB. Allowing the Permian Basin community to educate will foster the students' interest in STEM and inspire them to pursue STEM careers.
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.