Co2 relative permeability is a critical parameter affecting many aspects of Co2 injection for Enhanced Oil recovery and Co2 storage including; injectivity and trapped phase saturation.
In this study, we use measured Co2 - brine relative permeability data available in the literature to study the behaviour of the data obtained for various rocks. These measured Co2 relative permeabilities show large variations in the values of relative permeability and also in the trend of the relative permeability curves.
We identify the rock internal structure or quality as a controlling factor with considerable impact on Co2 relative permeability and we offer an explanation for the observed variation in Co2 relative permeability behaviour. We use a pore network model with different pore and throat distributions to verify the effect of rock pore and throat distributions on Co2 relative permeability. Based on our definition, a normal pore-throat distributions with similar connection produces a regular Co2 relative permeability curve shape which gives a high Co2 injection rate whereas in an abnormal pore-throat distribution with dissimilar connection, it is observed that the Co2 relative permeability curve shape is almost vertical .
We extended the work to the investigation of the impact of the rock internal structure on the Co2 injection characteristics particularly on Co2 injection rate. We found that normal pore-throat distributions with similar connection result in much higher Co2 injection rate than do the abnormal pore-throat distributions with dissimilar connection.
The results of this study will allow us to identify rocks that would be more suitable for Co2 injection (e.g., higher injectivity requiring lower number of injection wells) on the basis of the structure and distribution of the pores inside the rock.
Introduction and Objective.
In most petroleum engineering literatures, the relative permeability of Co2 has been studied for each formation separately and the main factors considered to affect the Co2 relative permeability are; fluid saturation, hysteresis and interfacial tension. As for a group of formations with different rock types, the difference in Co2 relative permeability curves is mainly attributed to rock type parameters. However, it has been found that even in a set of samples extracted from different formations in the same rock type or from a single formation, there is diversity in Co2 relative permeability curves. Rock pore structure or quality has been assumed to be responsible of the observed disparity, but no detailed explanation has been offered as to how it could results in different Co2 relative permeability curves for a set of formations in the same rock type. In this work, we are introducing an improved concept of pore and throat distribution, which will be used to interpret the observed differences in Co2 relative permeabilities.
The hybrid process is a technique which involves the co-injection of liquid solvent with steam in a similar steam assisted gravity drainage (SAGD) pattern. The combined process can significantly reduce the limitation of the pure SAGD process.
Numerous simulation studies have been previously conducted to understand the hybrid processes. However, most of the models suffer from the lack of an accurate equation-of-state (EOS)/viscosity models for the true estimation of the phase and volumetric behavior of solvent-bitumen-steam as well as the mixture viscosity at the edge oil-flow zone. The provided fluid model in this study is based on our extensive work done on the experimental analysis, and the modeling of viscosity and phase behavior of solvent and viscous oil mixtures for wide range of pressures and temperatures.
In this study, hydrocarbon additives such as C5, C6, C7, C8 and C12 are used as medium solvents and C15 is selected as the heavy solvent. First, the mechanism of the medium and heavy solvents and their impact at the oil-gas interface is discussed. It is found that the development of the edge oil-flow zone is significantly controlled by solvent type where different mechanisms based on K-values behavior exist for different solvents.
Finally, we developed the integrated optimization model which includes the reservoir SAGD pattern and the surface facility process. Moreover, the pipeline used to transfer the mixture of heavy oil (or bitumen) and solvent from surface process to the market is integrated and optimized. The overall net present value (NPV) of the field is calculated and optimized by selecting the main regression variables. We found that for the specific solvent type; the solvent amount, the injection pressure of the solvent and steam are the main parameters which significantly determine the success of such processes.
Our findings are significantly important for the future development of the solvent-SAGD pattern i.e. both reservoir and surface/pipe-line facilities. In addition, it can be implemented for any type of heavy oil field which still requires thermal methods to increase the oil recovery.
From last decades, SAGD process has been proven to be a promising oil-recovery process in bitumen deposits. However, the economics of SAGD is mainly influenced by first the natural gas used to generate the steam and second the water treatment and recycling. This is due to the consumption of a large amount of water and natural gas, which results in costly post-production water treatment and a significant amount of CO2 emission. The Hybrid process is another technique which involves the co-injection of liquid solvent with steam in a similar SAGD pattern. The combined process can significantly reduce the amount of energy, water and greenhouse gases compared to the SAGD process. Moreover, the main purpose of solvent additives to steam in an SAGD process is to take the advantage of steam for bringing heat to cold bitumen and also the solvent to dissolve into the bitumen and increase the economic efficiency of the process.
Low frequency shadows have long been accepted as direct hydrocarbon indicators, but few convincing examples have been published. A deliberate search for low frequency shadows on seismic data from multiple fields offshore Malaysia finds no clear candidates. Prospect-scale frequency shadows are difficult to detect with conventional seismic attributes because the subtle spectral changes caused by attenuation are masked by the much larger and more variable effects of reflection interference. Detectable low frequency shadows are too rare to serve as practical direct hydrocarbon indicators.
Low frequency shadows have been widely accepted as direct hydrocarbon indicators since the 1970s (Sheriff, 1975; Taner et al., 1979). The prevailing view is that “low frequency shadows often have been observed beneath amplitude anomalies associated with gas reservoirs” (Chopra and Marfurt, 2007, p. 141). The idea is appealing. A low frequency shadow is a zone in seismic data characterized by anomalously low frequencies that occurs beneath a causative body. The body strongly attenuates the seismic energy, preferentially reducing the high frequencies Seismic reflections within a shadow lack high frequency content relative to surrounding reflections. Shadows have fairly clear beginnings but tend to fade quickly with depth. Because gas sands are the chief cause of anomalous attenuation, low frequency shadows serve as hydrocarbon indicators, and reduce risk in bright spot exploration. The large and obvious effects of gas clouds, gas chimneys, and shallow gas are not considered here as they are not primary exploration targets, but instead indicate gas escaping from deeper levels (Brouwer et al., 2008; Ghazali et al., 2013).
In spite of a long history and popular acceptance, few examples of low frequency shadows have ever been published, and none are especially convincing hydrocarbon indicators. This contrasts markedly with the record of other hydrocarbon indicators, such as bright spots, flat spots, amplitude conformance to structure, and AVO, for which published examples are numerous and credible. This raises the question: Do low prospect-scale frequency shadows really exist?
We search for prospective frequency shadows in poststack seismic data from a number of producing fields offshore Malaysia. We employ conventional seismic trace attributes, frequency decay curves, and volume spectral decomposition. We review many gas sands, bright spots, and frequency anomalies, but none clearly constitute low frequency shadows.
We apply reflection strength, average frequency, and bandwidth attributes to poststack seismic data from offshore Malaysia to characterize patterns of spectral change and identify frequency anomalies. The frequency and bandwidth attributes represent averages weighted by the instantaneous power, and are derived in 30 ms (15 sample) windows. We supplement this analysis with a simple volume spectral decomposition that separates low and high frequency components of the seismic data to reveal local frequency anomalies.
Well intervention of subsea wells is commonly performed by positioning a rig or intervention vessel and connecting the rig to the subsea wellhead with a marine riser. Once the marine riser is connected to the subsea tree, the crown plugs are removed and normal well intervention services can be performed. Typically, subsea trees have upper and lower crown plugs for dual barrier redundant sealing. Crown plugs can be removed from the subsea tree using different methodologies; however, slickline is often the preferred method because of economics. Conventional slickline with toolstrings that create upward impact have been used successfully in shallow water. However, as development occurs at greater water depths, higher hydrostatic heads have made impact tools less effective. The major concern is that impact loads create only slight upward movement, and high forces attributed to hydrostatic pressure push the crown plugs back into the original sealbore. To overcome this limitation, a battery powered electromechanical pulling tool has been used to successfully pull numerous crown plugs in a variety of different conditions. The original electromechanical pulling tools where simple on/off devices that did not provide any information when the operation was unsuccessful. New technology has been developed that provides data to diagnose cases in which is not possible to pull the crown plug. The new technology has been deployed successfully and the post-job report is used to diagnose cases where pulling of the crown plug was unsuccessful. This paper discusses a job where the new technology provided data that clearly showed the tool supplied maximum rated force without being able to pull the crown plug. With this information the operator understood the situation and was able to move forward quickly with the correct tools to mitigate the circumstances. The understanding provided by the tool data enabled the operator to quickly resolve the situation, helping save substantial rig time in a deepwater environment.
Well intervention of subsea wells requires detailed planning before a rig or intervention vessel travels onsite. One of the first tasks performed during well interventions is pulling the subsea crown plugs in the wellhead. A portion of the planning process involves selecting a method to be used to remove the crown plugs from the subsea tree. Crown plugs can be pulled using a variety of methods, such as a rig, coiled tubing (CT), or possibly slickline. Although all of these methods have been employed, slickline is preferred because of its low cost, quick setup, and speed.
In shallow water, conventional slickline methods using jars have been successfully deployed to pull crown plugs. Slickline jars create very short duration high impact forces used to slowly work the crown plug out of the sealbore. This methodology works well in shallow water because hydrostatic pressure from the water column is typically less than the surface shut-in pressure.
Additionally, the presence of debris in the marine riser can cause additional issues. Debris present in the marine riser can fall and settle on top of the wellhead plugs. An accumulation of debris on top of the crown plug can make pulling more difficult.
In deeper water, hydrostatic pressure created by the water column can be greater than the surface shut-in pressure. With a large cross-sectional area crown plug, there can be a large differential pressure keeping the wellhead plug in place. Conventional slickline has extremely limited pull force because of low wire strength. Jar forces, even substantial ones, cannot work the plug out of the sealbore because, after each jar impact, the line must be relaxed to recock the jars. Every time the line is relaxed to recock the jars, the differential pressure pushes the plug fully back into its seat.
Gas hydrate formation and control is a critical flow challenge that many offshore oil and gas production operations encounter. Formation of hydrates can cause blockage of production flowlines, chokes and valves, which can result in catastrophic failures. Compared to other production problems, hydrate formation is a relatively new phenomenon that is becoming more and more significant with increasing subsea and deepwater developments as well as huge gas projects in the Middle East. The use of low dosage hydrate inhibitors (LDHIs), such as kinetic hydrate inhibitors (KHIs), offer an alternate technical solution to thermodynamic hydrate inhibitors by offering better economics, improved Health, Safety and Environmental (HS&E) performance and less demand on product transportation and storage.
This paper summarizes the history, evolution and current state of KHI laboratory testing requirements. Improvements in laboratory techniques to evaluate the performance of KHI in sweet and sour environments will be discussed. The results of the evaluation are based on laboratory conditions and the ability of a KHI to successfully inhibit hydrate formation in sweet and sour rocking cells. Recent testing has shown significant differences between sweet and sour environments and the ability of the KHI to successfully inhibit hydrate formation under laboratory conditions.
The secondary properties of a selected KHI are becoming more important so are advances in evaluating these properties, in particular the stability and applicability of a KHI under proposed system conditions. Hydrates may form different structures depending on the gas composition of the produced fluids. The nature of the KHI used needs to take into consideration. Recent product developments in this area show that these challenges can be met with appropriate lab testing.
Flow assurance is critical during the efficient production of hydrocarbons from offshore and subsea assets. Gas hydrate formation and control is a critical flow assurance challenge that many offshore oil and gas production operations encounter. The interaction of low-molecular weight gases such as small chain hydrocarbon, and acidic gases like carbon dioxide and hydrogen sulfide, with water under "high" pressure and "low" temperature within a pipeline can form gas hydrates. Gas hydrates are essentially a gas molecule encapsulated by water molecules which have an ice like appearance. Two types of hydrate structure form in gas pipelines, type II being the most common and associated with larger gas molecules such as ethane and propane and type I mainly associated with lean gas and/or carbon dioxide or hydrogen sulfide production. Gas hydrate crystals may agglomerate and/or anneal to form plugs that results in lost production and may incrase (HS&E) risks. Formation of hydrates can cause blockage of production flowlines, chokes and valves, which can result in potentially catastrophic failures.