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Collaborating Authors
Results
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)
Evaluation of Reservoir Connectivity from Downhole Fluid Analysis, Asphaltene Equation of State Model and Advanced Laboratory Fluid Analyses
Dong, Chengli (Shell) | Petro, David (Marathon) | Latifzai, Ahmad S. (Shell) | Zuo, Julian (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Characterization of complicated reservoir architecture with multiple compartments, baffles and tortuous connectivity is critical; additionally, reservoir fluids undergo dynamic processes (multiple charging, biodegradation and water/gas washes) that lead to complex fluid columns with significant property variation. Accurate understanding of both reservoir and fluids is critical for reserve assessment, field management and production planning. In this paper, a methodology is presented for reservoir connectivity analysis, which integrates reservoir fluid property distributions with an asphaltene Equation of State (EoS) model developed recently. The implications of reservoir fluid equilibrium are treated within laboratory experimentation and equation of state modeling. In addition to cubic EoS modeling for light end gradients, the industry's first asphaltene EoS the Flory-Huggins-Zuo EoS is successfully utilized for asphaltene gradients. This new EoS has been enabled by the resolution of asphaltene nanoscience embodied in the Yen-Mullins model. Specific reservoir fluid gradients, such as gas-oil ratio (GOR), composition and asphaltene content, can be measured in real time and under downhole conditions with downhole fluid analysis (DFA) conveyed by formation tester tools. Integration of the DFA methods with the asphaltene EoS model provides an effective method to analyze connectivity at the field scale, for both volatile oil/condensate gas reservoirs with large GOR variation, and black oil/mobile heavy oil fields with asphaltene variation in dominant. A field case study is presented that involves multiple stacked sands in five wells in a complicated offshore field. Formation pressure analysis is inconclusive in determining formation connectivity due to measurement uncertainties; furthermore, conventional PVT laboratory analysis does not indicate significant fluid property variation. In this highly under-saturated black oil field, measurement of asphaltene content using DFA shows significant variation and is critical for understanding the reservoir fluid distribution. When integrated with the asphaltene EoS model, connectivity across multiple sands and wells is determined with high confidence, and the results are confirmed by actual production data. Advanced laboratory fluid analysis, such as two-dimensional gas chromatography, is also conducted on fluid samples, which further confirms the result of the DFA and asphaltene EoS model.
- North America > United States (0.68)
- North America > Canada > Alberta (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
- Geology > Geological Subdiscipline > Geochemistry (0.48)
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)
Integration Of Wireline And Modeling For Production Optimization
Roman, Silvia (Pemex) | Meza, Jose Angel (Pemex) | Ramirez, Jose Ramon (Pemex) | De Nicolais, Nelly (Schlumberger) | Quintero, Oscar (Schlumberger) | Granados, Jorge (Schlumberger) | Peyret, Emilie (Schlumberger) | Waggoner, John (Schlumberger) | Mullins, Oliver C. (Schlumberger)
ABSTRACT: Reservoir characterization and predictions of production remain central concerns of operating companies. Wireline formation tester tools (WFT) figure prominently for these objectives for sample acquisition, downhole fluid analysis (DFA), and pressure transient applications. Reservoir modeling tools Petrel and Eclipse are heavily utilized to frame reservoir data and to predict production. A solutions orientation necessitates integration of data acquisition and modeling especially within land, development settings. Here, utilization of MDT fluid and pressure data is used in a direct manner to assist in constraining modeling of production in new wells. The approach taken here is to use MDT data from several nearby wells to predict production in newly drilled wells. Local versus field wide analysis is used for three reasons 1) high resolution in a local region is preferred over lower resolution field-wide modeling 2) there is greater confidence in reservoir models in a local area, and 3) the effect of distant wells is minimal. This integration and feedback between WFT data and reservoir modeling is effective at reducing uncertainties in reservoir characterization. INTRODUCTION The value of running services such as the MDT and exploiting Petrel modeling for exploration & appraisal in high tier markets such as Deepwater is unquestioned. Likewise, these services and protocols are heavily utilized in a production setting for massive fields in the Persian Gulf. Nevertheless, the same services and workflows can be successfully exploited in much smaller fields in a land, production setting. In this paper, we treat an oilfield operated by Pemex. MDT-DFA data is key for evaluation of the fluids in the different producing intervals, and for understanding water breakthrough.[1] The MDT provides basic pressure measurements which are always very useful in development. The XPT is also utilized in the field for this purpose. The MDT also provides fluid sampling and DFA.
- North America > Mexico (0.87)
- Asia > Middle East > Saudi Arabia > Arabian Gulf (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > Mexico Government (0.55)
Downhole Fluid Analysis And Asphaltene Nanoscience For Reservoir Evaluation Measurement
Mullins, Oliver C. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Andrew, A. Ballard (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Andrew, E. Pomerantz (Schlumberger) | Dong, Chengli (Shell Exploration and Production Inc) | Elshahawi, Hani (Shell Exploration and Production Inc) | Cribbs, Myrt E. (Chevron North America)
ABSTRACT: In recent years, several major advances have taken place in asphaltene science and have been codified in the Yen-Mullins Model. Specifically, these advances embody the characterization of the nanocolloidal structure of asphaltenes in crude oil. They also are applicable to surface science at the molecular level and provide a foundation for understanding wettability. This nanoscience also establishes the foundation for the โgravity termโ enabling the development of the industry's first predictive equation of state of asphaltene gradients in the Flory-Huggins-Zuo (FHZ) equation of state. The FHZ equation coupled with downhole fluid analysis (DFA) data has been used to address major reservoir concerns including reservoir connectivity, heavy oil columns, tar mats, and reservoir fluid disequilibrium in many case studies. This paper provides an overview of the developments in asphaltene science, surface science and the development of the FHZ EoS. We review the many classes of case studies linking the FHZ EoS with DFA, with emphasis on the corresponding significant improvement of capability in each focus of study. The coupling of new science and new technology is shown to yield tremendous improvements in reservoir characterization. INTRODUCTION An ancient truism taught in elementary school is "matter is composed of solids, liquids and gases." True to form, reservoir crude oils contain dissolved gases, hydrocarbon liquids and solids, the asphaltenes. Petroleum gases and liquids have been relatively straightforward to analyze by standard analytical chemistry techniques, and there has been no fundamental disagreement about their chemical nature. In stark contrast, asphaltenes have been the subject of enormous debate; even molecular weight was disputed by a factor of one million![1] The cost of this scientific deficiency on all aspects of the oil industry has been severe. For example, in reservoir engineering, reservoir fluids are often modeled using cubic equations of state.
- North America > United States (1.00)
- Europe (1.00)
- Asia (1.00)
- Geology > Geological Subdiscipline (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.36)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.30)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tonga Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tahiti Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Caesar Field (0.99)
- (15 more...)
Reservoir Characterization From Analysis Of Reservoir Fluid Property Distribution And Asphaltene Equation Of State Model
Dong, Chengli (Shell) | Petro, David (Marathon) | Latifzai, Ahmad S. (Shell) | Zuo, Julian Y. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Hayden, Ron S. (Schlumberger)
ABSTRACT: Characterization of complicated reservoir architecture with multiple compartments, baffles and tortuous connectivity is critical; additional complications arise because reservoir fluids undergo dynamic processes (multiple charging, biodegradation and water/gas washes) that lead to fluid columns with significant property variation. Accurate understanding of both reservoir and fluids is critical for reserve assessment, field management and production planning. In this paper, a methodology is presented for reservoir connectivity analysis from integration of reservoir fluid property distributions, a new asphaltene Equation of State (EoS) model, and advanced laboratory fluid analysis. Detailed reservoir fluid property distribution, such as gas-oil ratio (GOR), composition, density and asphaltene content, is measured in real time and at downhole conditions with downhole fluid analysis (DFA) conveyed by a formation tester tool. The new asphaltene EoS model describes fluid distributions in a connected reservoir with the fluids in equilibrium. Integration of the DFA technique with the asphaltene EoS model provides an effective method to analyze connectivity in field scale. This method works for both volatile oil/condensate gas reservoirs with large GOR variation and black oil fields with asphaltene variation. The field case study presented herein involves multiple stacked sands in five wells in a complicated offshore field. Formation pressure analysis is inconclusive in determining reservoir connectivity due to measurement uncertainties; furthermore, conventional PVT laboratory analysis does not indicate significant fluid property variation. In this highly under-saturated black oil field, asphaltene content from the DFA technique shows significant variation and is critical for understanding the reservoir fluid distribution. When the DFA results are integrated with the asphaltene EoS model, reservoir connectivity across multiple sands and wells is determined with high confidence, and the results are confirmed by production data. Advanced laboratory fluid analysis, such as two-dimensional gas chromatography, further confirms the result from the DFA and asphaltene EoS model.
- North America > United States (0.47)
- North America > Canada > Alberta (0.44)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
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...)