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Collaborating Authors
Flow Assurance
Heavy Oil and Tar Mat Characterization Within a Single Oil Column Utilizing Novel Asphaltene Science
Seifert, Douglas J. (Saudi Aramco) | Qureshi, Ahmed (Schlumberger) | Zeybek, Murat (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
ABSTRACT A Jurassic oil field in Saudi Arabia is characterized by black oil in the crest, with heavy oil underneath and all underlain by a tar mat at the oil-water contact (OWC). The viscosities in the black oil section of the column are similar throughout the field and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large, continuous increase in asphaltene content with increasing depth extending to the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. A simple new formalism, the Flory-Huggins-Zuo (FHZ) Equation of State (EoS) incorporating the Yen-Mullins model of asphaltene nanoscience, is shown to account for the asphaltene content variation in the mobile heavy oil section. Detailed analysis of the tar mat shows significant nonmonotonic content of asphaltenes with depth, differing from that of the heavy oil. While the general concept of asphaltene gravitational accumulation to form the tar mat does apply, other complexities preclude simple monotonic behavior. Indeed, within small vertical distances (5 ft) the asphaltene content can decrease by 20% absolute with depth. These complexities likely involve a phase transition when the asphaltene concentration exceeds 35%. Traditional thermodynamic models of heavy oils and asphaltene gradients are known to fail dramatically. Many have ascribed this failure to some sort of chemical variation of asphaltenes with depth; the idea being that if the models fail it must be due to the asphaltenes. Our new simple formalism shows that thermodynamic modeling of heavy oil and asphaltene gradients can be successful. Our simple model demands that the asphaltenes are the same, top to bottom. The analysis of the sulfur chemistry of these asphaltenes by X-ray spectroscopy at the synchrotron at the Argonne National Laboratory shows that there is almost no variation of the sulfur through the hydrocarbon column. Sulfur is one of the most sensitive elements in asphaltenes to demark variation. Likewise, saturates, araomatics, resins and asphaltenes (SARA); measurements also support the application of this new asphaltene formalism. Consequently, the asphaltenes are very similar, and our new FHZ EoS with the Yen-Mullins formalism properly accounts for heavy oil and asphaltene gradients.
- North America > United States (0.94)
- Asia > Middle East > Saudi Arabia (0.48)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
ABSTRACT Tar mats at the oil-water contact (OWC tar mats) in oilfield reservoirs can have enormous, pernicious effects on production due to possibly preventing of any natural water drive and precluding any effectiveness of water injectors into aquifers. In spite of this potentially huge impact, tar mat formation is only now being resolved and integrated within advanced asphaltene science. Herein, we describe a very different type of tar mat which we refer to as a "rapid-destabilization tar mat"; it is the asphaltenes that undergo rapid destabilization. To our knowledge, this is the first paper to describe such rapid-destabilization tar mats at least in this context. Rapid-destabilization tar mats can be formed at the crest of the reservoir, generally not at the OWC and can introduce their own set of problems in production. Most importantly, rapid-destabilization tar mats can be porous and permeable, unlike the OWC tar mats. The rapid-destabilization tar mat can undergo plastic flow under standard production conditions rather unlike the OWC tar mat. As its name implies, the rapid-destabilization tar mat can form in very young reservoirs in which thermodynamic disequilibrium in the oil column prevails, while the OWC tar mats generally take longer (geologic) time to form and are often associated with thermodynamically equilibrated oil columns. Here, we describe extensive data sets on rapid-destabilization tar mats in two adjacent reservoirs. The surprising properties of these rapid-destabilization tar mats are redundantly confirmed in many different ways. All components of the processes forming rapid-destabilization tar mats are shown to be consistent with powerful new developments in asphaltene science, specifically with the development of the first equation of state for asphaltene gradients, the Flory-Huggins-Zuo Equation, which has been enabled by the resolution of asphaltene nanostructures in crude oil codified in the Yen-Mullins Model. Rapid-destabilization tar mats represent one extreme while the OWC tar mats represent the polar opposite extreme. In the future, occurrences of tar in reservoirs can be better understood within the context of these two end members tar mats. In addition, two reservoirs in the same minibasin show the same behavior. This important observation allows fluid analysis in wells in one reservoir to indicate likely issues in other reservoirs in the same basin.
- Asia > Middle East > Saudi Arabia (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract A Jurrasic oilfield in Saudi Arabia is characterized by black oil in the crest and with mobile heavy oil underneath and all underlain by a tar mat at the oil-water contact. The viscosities in the black oil section of the column are fairly similar and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large continuous increase in asphaltene content with increasing depth extending to the tar mat. The tar shows very high asphaltene content but not monotonically increasing with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from several to ~ 1000 centipoise in the mobile heavy oil and increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. Conventional PVT modeling of this oil column grossly fails to account for these observations. Indeed, the very large height in this oil column represents a stringent challenge for any corresponding fluid model. A simple new formalism to characterize the asphaltene nanoscience in crude oils, the Yen-Mullins model, has enabled the industry's first predictive equation of state (EoS) for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS. For low GOR oils such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the FHZ EoS employing the Yen-Mullins model accounts for the major property variations in the oil column and by extension the tar mat as well. Moreover, as these crude oils are largely equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically improving understanding of important constraints on oil production in oil reservoirs.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.48)
Abstract Many techniques are used in industry to determine reservoir hydraulic connectivity from static data. These can be rock-based techniques such as seismic mapping, well to well correlations and geological modeling. Or they can be fluid based techniques such as pressure and fluid gradients. Fluid pressure gradients acquired with formation testers have long been popular but they are understood to be able to identify a lack of connectivity and cannot necessarily prove the presence of connectivity. Recent work has shown that mapping fluid gradients can be much more definitive. For light fluids this mapping is based on the gas-oil ratio (GOR). For heavier fluids, with little GOR variation, this technique requires mapping a different parameter. It has been suspected that asphaltene content was the parameter to map, but until recently the science of asphaltene prediction was unclear. Recent advances in asphaltene science have now clarified the mechanism for asphaltene distribution in the reservoir and gradient prediction is now possible. And most fortunately it turns out that the asphaltene gradient is relatively easy to measure in-situ. In this paper we present the science behind asphaltene gradient prediction and show how fluid gradients are a superior way to infer reservoir connectivity. We then present data from an Eastern Siberia oilfield where asphaltene gradients are determined in-situ with a wireline formation tester. These gradients are verified by later comparison to laboratory measurements. Finally and most importantly, we show also how the asphaltene content is used to predict reservoir connectivity both vertically and laterally.
- Asia (1.00)
- North America > United States > Texas (0.46)
Downhole Fluid Analysis and Asphaltene Nanoscience Coupled with VIT for Risk Reduction in Black Oil Production
Mishra, Vinay K. (Schlumberger) | Skinner, Carla (Husky Energy) | MacDonald, Dennis (Husky Energy) | Hammou, Nasr-eddine (Husky Energy) | Lehne, Eric (Schlumberger) | Wu, Jiehui (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Dong, Chengli (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract It has long been recognized that condensates can exhibit large compositional gradients. It is increasingly recognized that black oil columns can also exhibit substantial gradients. Moreover, significant advances in asphaltene science have provided the framework for modeling these gradients. For effective field development planning, it is important to understand possible variations in the oil column. These developments in petroleum science are being coupled with the new technology of downhole fluid analysis (DFA) to mitigate risk in oil production. In this case study, DFA measurements revealed a large (10ร) gradient of asphaltenes in a 100-m black oil column, with a corresponding large viscosity gradient. This asphaltene gradient was traced to the colloidal description of the asphaltenes, which yielded two conclusions: the asphaltenes are vertically equilibrated, consequently vertical connectivity is indicated, and the asphaltenes are partially destabilized. Vertical interference testing (VIT) was performed at several depths and confirmed the vertical connectivity of the oil column, with four of the five tests showing unambiguous vertical connectivity consistent with the overall connectivity implied by DFA. Geochemical analysis indicates that the instability was due to some late gas and condensate entry into the reservoir. For mitigation of production risk, flow assurance studies were performed and showed that while the asphaltenes are indeed partially destabilized, there is no significant associated problem. Moreover, thin sections of core were analyzed to detect possible bitumen. A very small quantity of bitumen was found, again confirming the asphaltene analysis; however, geochemical studies and flow assurance studies confirmed that this small amount of bitumen is not expected to create any reservoir issues. Using new science and new technology to identify and minimize risk in oil production in combination with pressure transients addressed reservoir connectivity and provided a robust, positive assessment.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.75)
ABSTRACT: Heavy oils frequently exhibit large compositional gradients. However, previously, there had been no predictive equation of state model to treat gradients in heavy oils, thereby largely precluding understanding and modeling of these gradients. Recent advances in asphaltene nanoscience include delineation of the colloidal nature of asphaltenes in crude oils including mobile heavy oils, the Yen-Mullins model. In turn this has led to the industry's first predictive asphaltene equation of state, the Flory-Huggins-Zuo EOS. For heavy oils with a low gas/oil ratio (GOR), this EOS has a very simple form. This simple model is shown to apply specifically to a heavy oil column in a producing field in Ecuador. This is the first demonstration of its kind. A large asphaltene gradient with its associated huge viscosity gradient is shown to be consistent with a vertically equilibrated distribution of asphaltenes. Simple models are given to provide a first order prediction of the viscosity gradients spanning a factor of 30. Nuclear magnetic resonance (NMR) characterization of these gradients is shown to be effective. In this field, production has resulted in large and variable pressure depletion. Nevertheless, the fluid compositional distribution in large measure appears to reflect that which existed prior to production. Fluid and pressure measurements are known to be complementary for formation evaluation prior to production. Here, we show that fluid and pressure measurements are complementary after significant production. New directions for characterization of heavy oil columns are discussed focusing on recent science and technology advances. INTRODUCTION In years past, there had been a gross deficiency in the thermodynamic modeling of crude oils. By revealing fluid complexities in real time during the wireline job, DFA enables matching the complexity and cost of such operations to the complexity of the oil column.
- Europe (0.69)
- South America (0.67)
- North America > United States > Colorado (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (3 more...)
Abstract Sand screens for specific applications are often selected by reference to the results obtained from laboratory sand retention testing. Some recent publications have highlighted the problems of running some types of sand retention tests (slurry tests) at high flow rates, such that the differences between wire wraps screens and metal mesh screens may be exaggerated. With these in mind and also to address some general concerns of the authors ways to reduce flow rates in laboratory slurry tests to more realistic levels have been investigated. This has created some unforeseen effects which are discussed; video has proved invaluable in understanding these unforeseen effects. In addition, an attempt has been made to better define plugging within sand retention tests by relating the pressure build-up gradient from slurry tests to characteristics of the sand itself. Although the pressure gradient generally correlates to certain sand size and sorting parameters the spread in data suggests another factor is important. The purpose of this work is to try and better define the differences in performance between different screen designs, primarily wire wrap and metal mesh screens, in order to better define their application envelopes in terms of sand quality and hence develop more definitive guidelines for screen selection.
- North America > United States (0.28)
- Europe > Netherlands (0.28)
- Well Completion > Sand Control > Screen selection (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)