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Integrated Rock and Fluid Workflow to Optimize Geomodeling and History Matching
Abstract
Optimized geomodeling and history matching of production data is presented by utilizing an integrated rock and fluid workflow. Facies identification is performed by use of image logs and other geological information. In addition, image logs are used to help define structural geodynamic processes that occurred in the reservoir. Methods of reservoir fluid geodynamics are used to assess the extent of fluid compositional equilibrium, especially the asphaltenes, and thereby the extent of connectivity in these facies. Geochemical determinations are shown to be consistent with measurements of compositional thermodynamic equilibrium. The ability to develop the geo-scenario of the reservoir, the coherent evolution of rock and contained fluids in the reservoir over geologic time, improves the robustness of the geomodel. In particular, the sequence of oil charge, compositional equilibrium, fault block throw, and primary biogenic gas charge are established in this middle Pliocene reservoir with implications for production, field extension,and local basin exploration. History matching of production data prove the accuracy of the geomodel; nevertheless, refinements to the geomodel and improved history matching were obtained by expanded deterministic property estimation from wireline log and other data. Theearly connection of fluid data, both thermodynamic and geochemical, with relevant facies andtheir properties determination enables a more facile method to incorporate this data into the geomodel. Logging data from future wells in the field can be imported into the geomodel allowingdeterministic optimization of this model long after production has commenced. While each reservoir is unique with its own idiosyncrasies, the workflow presented here is generally applicable to all reservoirs and always improves reservoir understanding.
Waterflooding in deepwater reservoirs typically involves injecting seawater or produced water from the surface via pumps into injection wells. This technique is often cost-prohibitive for many reservoirs and poses significant mechanical/operational risks. This paper discusses how one Gulf of Mexico (GOM) operator overcame all these challenges using smart well technology to implement the first controlled dumpflood in deepwater GOM and boosted the injection rate, reservoir pressure, and recovery from a reservoir at a depth of 20,000 ft.
In a typical dumpflood project, uncontrolled water production from the aquifer and subsequent injection into the target zone occurs downhole within the same wellbore. Therefore, typical surface and downhole complexities associated with conventional waterflood projects can be avoided. In this first deepwater GOM controlled dumpflood well, the controlled water flow (≥20,000 bbl/d) is directed from the source aquifer to the target oil zone via inflow control valves (ICV). The ICV, downhole permanent pressure gauges, and the downhole flowmeter provide complete surveillance and control of the injection operation to achieve reservoir management and optimize the waterflood objectives.
A world-class Pliocene oil reservoir in the deepwater GOM underwent significant pressure depletion due to a weak water-drive mechanism. Extensive subsurface studies and modeling suggested great rock quality and reservoir connectivity, favorable oil-water mobility ratios, and significant upside potential making this reservoir a perfect candidate for waterflooding. Given topsides facility space constraints, a topsides injection was ruled out. Seawater injection via subsea pumping was deemed risky and marginally economical given the high cost and low commodity prices. The asset team then brainstormed ways to minimize the cost and overcome the associated risks and challenges. The asset team envisioned a dumpflood scenario would overcome all the challenges, but a dumpflood had not previously been implemented in the deepwater GOM. From a technical standpoint, all the known risks were identified and addressed, and a low risk factor was determined for this project.
After a complex well completion job, the injection rate was ramped-up to ≥20,000 bwpd water via the ICV. An immediate uptick in reservoir pressure and production rate was observed in the producer well 3,000 ft away. Continuous injection has resulted in reservoir pressure and flowrate increases by at least 1,000 psi and 4,000 bopd, respectively, consistent with reservoir modeling estimates.
The operator was successful in implementing an existing technology in a unique way in the deepwater environment. A naturally occurring water source at a depth of 19,000 ft was efficiently harvested to increase recovery from a reservoir at a fraction of the cost of a conventional deepwater waterflood project. Great interdisciplinary collaboration and forward thinking enabled the success of this unique project, opening up tremendous possibilities to increase recovery from other fields where a conventional waterflood may not be justifiable.
The initial thermal reactions of aromatic hydrocarbons are relevant to many industrial applications. However, tracking the growing number of heavy polycyclic aromatic hydrocarbon (PAH) products is extremely challenging because many reactions are unfolding in parallel from a mixture of molecules. Herein, we studied the reactions of 2,7-dimethylpyrene (DMPY) to decipher the roles of methyl substituents during mild thermal treatment. We found that the presence of methyl substituents is key for reducing the thermal severity required to initiate chemical reactions in natural molecular mixtures. A complex mixture of thermal products including monomers, dimers, and trimers was characterized by NMR, mass spectrometry, and noncontact atomic force microscopy (nc-AFM). A wide range of structural transformations including methyl transfer and polymerization reactions were identified. A detailed mechanistic understanding on the roles of H radicals during the polymerization of polycyclic aromatic hydrocarbons was obtained.
Many Upper Tertiary reservoirs from the Gulf of Mexico (GoM) are sandstones deposited either in channel-levee systems or lobe systems in the intra-slope deepwater environment. One of the major uncertainties about those reservoirs is their distribution, which is likely controlled by salt tectonics. The current salt structure, however, does not represent the salt structure when the sands were deposited. It is difficult, if not impossible, to restore the salt history based on current salt structures. Salt movement resulted in a great amount of deformed shale in GoM. Borehole images on the other hand can be used to characterize the internal structure or texture of deformed shale; and the dips of deformed shale from borehole images may be used to define the paleo slope direction, which controls the movement of deformed shale. The internal structure or texture of deformed shale, therefore, may provide some information about the history of salt movement, which may also control the sand distribution. In this integrated study, all the available data, including borehole images, seismic volumes, and other petrophysical logs, were used to characterize the reservoir sands and shales. The reservoir sands are mainly composed of amalgamated sand, layered sand, and laminated sandstone. Based on dips from borehole images, paleo flow directions of reservoir sands were defined. The shales are categorized as hemipelagic shale and deformed shale. The hemipelagic shale has relatively lower and consistent dips; whereas deformed shale has relatively higher variable in both dip magnitude and dip azimuth. The integrated study suggests the main reservoir of the field is submarine lobe sands deposited above an allochthonous salt in the basin. The evacuation of the salt body below the basin created small geographic lower area for sand lobes to accumulate. The dips from the deformed shale provided information about the center of the small (or mini) basin, thus established a relationship between the dip pattern and sandstone distribution. If this relationship is valid for the other upper Tertiary deformed shale in the GoM area, a new method can be developed, which may enable us to predict the sandstone distribution using borehole images and provide guidance for petroleum evaluation and field development in the future.
This study addresses the effect of sample preparation conditions on the structural integrity and composition of heavy hydrocarbon mixtures imaged by non-contact atomic force microscopy (nc-AFM). We designed and prepared a set of organic molecules mimicking well-accepted key characteristics of heavy oil asphaltenes including molecular architecture, molecular weight, boiling point, atomic H/C ratio and bond strength. We deliberately focused on multi-core molecule structures with long aliphatic linkers as this architecture was largely absent in previous nc-AFM studies of petroleum samples. The results confirm that all these molecules can be successfully imaged and remain intact under the same preparation conditions. Moreover, comparison with ultra-high resolution FT ICR-MS of a steam-cracked tar asphaltene sample suggests that the single molecules identified by nc-AFM span the entire molecule spectrum of the bulk sample. Overall, these results suggest that petroleum molecules within the scope of chosen molecules studied herein can be prepared intact and without bias and the imaged data can be representative.
We designed and studied hydrocarbon model compounds by high-resolution noncontact atomic force microscopy. In addition to planar polycyclic aromatic moieties, these novel model compounds feature linear alkyl and cycloaliphatic motifs that exist in most hydrocarbon resources – particularly in petroleum asphaltenes and other petroleum fractions – or in lipids in biological samples. We demonstrate successful intact deposition by sublimation of the alkyl-aromatics, and differentiate aliphatic moieties from their aromatic counterparts which were generated from the former by atomic manipulation. The characterization by AFM in combination with atomic manipulation provides clear fingerprints of the aromatic and aliphatic moieties that will facilitate their assignment in a priori unknown samples.
The development of a new two-constant equation of state in which the attractive pressure term of the semiempirical van der Waals equation has been modified is outlined. Examples of the use of the equation for predicting the vapor pressure and volumetric behavior of single-component systems, and the phase behavior and volumetric behavior of binary, ternary, and multicomponent systems are given. The proposed equation combines simplicity and accuracy. It performs as well as or better than the Soave-Redlich-Kwong equation in all cases tested and shows its greatest advantages in the prediction of liquid phase densities.
Laser desorption laser ionization mass spectra of 23 model compounds and 2 petroleum asphaltene samples are presented. These experiments involved desorption by irradiation with the 10.6 μm output of a CO2 laser followed by single-photon ionization with the 157 nm output of a fluorine excimer laser. The average molecular weight of the asphaltene samples agrees closely with that found previously using multiphoton ionization with the 266 nm output of a Nd:YAG laser. The fragmentation behavior as a function of ionization laser pulse energy is studied to evaluate which families of model compounds fragment differently from asphaltenes and, hence, can be excluded from being dominant in asphaltenes. All model compounds having one aromatic core with and without various pendant alkyl groups show little to no fragmentation, mimicking the behavior observed for the two asphaltene samples, whereas all model compounds having more than one aromatic core show energy-dependent fragmentation. These observations support the contention that the dominant structural character of asphaltenes is island-like.
The Yen?Mullins model, also known as the modified Yen model, specifies the predominant molecular and colloidal structure of asphaltenes in crude oils and laboratory solvents and consists of the following: The most probable asphaltene molecular weight is ?750 g/mol, with the island molecular architecture dominant. At sufficient concentration, asphaltene molecules form nanoaggregates with an aggregation number less than 10. At higher concentrations, nanoaggregates form clusters again with small aggregation numbers. The Yen?Mullins model is consistent with numerous molecular and colloidal studies employing a broad array of methodologies. Moreover, the Yen?Mullins model provides a foundation for the development of the first asphaltene equation of state for predicting asphaltene gradients in oil reservoirs, the Flory?Huggins?Zuo equation of state (FHZ EoS). In turn, the FHZ EoS has proven applicability in oil reservoirs containing condensates, black oils, and heavy oils. While the development of the Yen?Mul
The most important attribute of any chemical compound is its elemental constituents. There is, fortunately, no uncertainty
about the elemental composition of asphaltenes. The second most important attribute of any chemical compound is its molecular
structure and, as a prerequisite to that information, molecular weight. Although the set of structures of individual chemical
units constituting asphaltene, such as the number of fused aromatic rings, length of aliphatic chains, and common functional
groups is mostly agreed upon, the asphaltene molecular weight has been the subject of a large and long-standing controversy.
For the most part, literature reports differ by a factor of 10, but some reports differ by many orders of magnitude. The question
is essentially if and how the chemical units are linked. These uncertainties are exacerbated by the corresponding possibilities
that different asphaltenes are variable, thus prohibiting facile comparison of results across different laboratories on different
asphaltenes. This controversy has retarded the development of asphaltene science in that knowledge of structure–function relations
is precluded if the structure is unknown. Consequently, a phenomenological approach has been routine in asphaltene science.
To understand the present-day fluid and geologic properties of reservoirs, it is best to understand how these properties evolved over geologic time. For reservoir structure, the protocol for evaluation always incorporates the geologic history of the reservoir comprised of depositional setting and postdeposition alteration or structural geodynamics. In contrast, a similar protocol had almost never been used for the fluids contained in the reservoir until now. Trap filling involves concepts of petroleum systems, a mature discipline. However, there had been little modeling or understanding of the myriad processes of postdeposition alterations of the reservoir fluids during and after trap filling to present day. Indeed, there was no name for this discipline; we have named it, reservoir fluid geodynamics (RFG). This former deficiency is now resolved with RFG thereby greatly improving the ability to elucidate fluid complexities in reservoirs such as viscosity variations, heavy oil and tar mat formations, and gas–oil ratio gradients of varying magnitudes. In addition, because fluids respond to their container, RFG can also address structural complexities such as reservoir connectivity and its inverse, compartmentalization, fault block migration, reservoir baffling, and low-productivity index. A comprehensive approach combining structural and RFG provides robust analyses that can be used as a benchmark for data acquired across all disciplines. RFG has been enabled by key engineering advances in downhole fluid analysis and by key scientific advances in asphaltene thermodynamics of reservoir fluids. Specifically, asphaltene gradients are modeled with the Flory–Huggins–Zuo Equation of State with its reliance on the Yen–Mullins model of asphaltenes. When significant scientific and engineering advances are strongly coupled, revolutionary applications often follow; this is shown to apply here, in the oil industry.
Fluid distributions throughout oilfield reservoirs have been measured with increasing accuracy and coverage, both vertical and laterally, in recent years. Currently, a routine observation is that, when reservoir crude oils are in thermodynamic equilibrium, then the reservoir is a single flow unit with fluid flow communication, addressing the most important oil production risk associated with reservoir structure. The most accurate method of determining fluid equilibration is by measurement and analysis of the distribution of dissolved (or suspended) asphaltenes in the oil. This analysis employs the Flory-Huggins-Zuo equation of state (EoS) with its reliance on the Yen-Mullins model of asphaltene nanostructures. This capability has enabled the introduction of a new technical discipline, reservoir fluid geodynamics, which provides a significant advance in the understanding of oilfield reservoirs. Other reservoir fluid components are also measured to assess equilibration of reservoir fluids, including dissolved gas, liquid-phase components, various biomarkers, and methane isotopic ratios. Often, there is a single species of asphaltenes in the reservoir in accordance with the Yen-Mullins model (molecules, nanoaggregates, and clusters). However, for some reservoirs, two species of asphaltenes are evident. These reservoirs provide a stringent test to (1) discern nanostructures of asphaltenes and (2) determine whether there are other prominent aggregate species of asphaltenes in addition to those indicated in the Yen-Mullins model. This paper explores five reservoirs: three of these reservoirs exhibit one dominant species; two exhibit two species of the Yen-Mullins model; and none of the reservoirs exhibits additional species, providing validation of asphaltene nanostructures in the Yen-Mullins model and its application with the Flory-Huggins-Zuo EoS for novel characterization of reservoirs.
Previously, asphaltene science had been saddled with many significant uncertainties regarding molecular weight, molecular structure, and nanocolloidal characteristics in laboratory solvents and in crude oils. These debates were of sufficient magnitude to forestall development and utility of asphaltene modeling for various applications. In the last two decades, advances in asphaltene science using many sophisticated techniques have greatly reduced corresponding uncertainties enabling development and application of simple asphaltene models for a variety of applications including surface and bulk properties of crude oils. In turn, these models have even led to a powerful, new discipline in the characterization of oilfield reservoirs, reservoir fluid geodynamics. Despite the convergence of results from diverse methods in asphaltene science, some current literature retains the same language as the former debilitating debates, thereby adding to confusion. This is especially true for asphaltene molecular architecture with regard to the debate of island with a single aromatic core vs archipelago with cross-linked aromatic cores. In particular, newly identified structures in asphaltenes such as molecules with a single, aryl-linked aromatic core have been assigned to both island and archipelago in different publications. Here, we provide an overview of key findings in asphaltene science with a focus on their implications for reservoir fluid thermodynamics. The applications of simple and complex asphaltene models are discussed with regard to interfacial properties. The relative importance of current debates in the literature in contrast to those of two decades ago are discussed. We propose use of a third class of molecular architecture: molecules with a “single, aryl-linked, aromatic core”; or the shorthand “aryl-linked core”. Molecular structural characterization of asphaltenes reviewed herein show that asphaltenes are dominated by island structures, but some asphaltenes also have a secondary content of structures with an aryl-linked core. This new classification “aryl-linked core” is to be added to the island and archipelago designations, aiding in establishing structure-function relations of asphaltenes. The “aryl-linked core” structure is defined as having a single, contiguous sp2 hybridized carbon network containing one or more aryl linkages in which adjacent aromatic rings are directly bonded together but do not share a common bond in a ring. In contrast, a traditional island structure also has a single, contiguous sp2 hybridized carbon network, but has adjacent aromatic rings exclusively fused (sharing a common bond in a ring) with no aryl linkages. The definition of archipelago remains unchanged and consists of multiple, discontinuous sp2 hybridized carbon networks in which these different aromatic ring systems are connected by one or more sp3 hybridized carbons. From an aggregation standpoint, both the island and aryl-linked core structures have predominantly a single intermolecular binding site per molecule; that structure is consistent with the observed asphaltene behavior of forming nanoaggregates but not gels at low concentrations. In contrast, the archipelago structure has multiple binding sites per molecule, which is consistent with gel formation, contrary to asphaltene behavior. Archipelago molecules are not found in asphaltenes in detailed studies discussed herein. The analysis of model archipelago compounds is discussed to validate the methodologies of their detection. In addition, to cleave aromatics off the molecule, the island requires cleaving multiple aromatic bonds, the aryl-linked core requires cleaving an aryl bond, and the archipelago requires cleaving an alkyl bond. Thus, the three structures are distinct in aggregation propensities and reaction chemistry. In a broader context, the advances in asphaltene science have ushered in powerful, new applications that are continuing to expand.
Wireline formation testing has evolved from discrete pressure measurements, introduced in the 1950s to measuring pressure gradients and fluid contacts since the 1970s. Technology introduced in the late 1980s and onwards added interval pressure transient testing, focused sampling, and downhole fluid analysis. Thirty years later, this paper shows data examples of a recently developed formation testing platform in a wide range of environments, and applications, that change how we plan, acquire, and use formation testing.
The dual-flow-line architecture of the formation testing platform is designed to systematically address shortcomings of legacy technology, enabling focused sampling in the tightest conventional formations, as well as transient testing in high mobility environments. Specialized pre-job planning software evaluates conveyance options to minimize friction and borehole contact, estimates the available flow rate, compares cleanup performance of the different inlets, and simulates transient testing responses. During the operation, the platform uses hardware embedded automation algorithms that execute routine tasks in a consistent and highly efficient manner, leaving more time for the user to focus on data quality and value of the measurements.
Case studies from Mexico, Norway, and the US demonstrate specific improvements in capability and performance. Field data from Mexico shows focused sampling of gas condensate from a heterogeneous submillidarcy carbonate formation in an HP/HT well drilled with oil-based mud. Controlled downhole decompression of crude oil in the flowline at a sampling station in Norway enabled real-time measurement of its bubblepoint pressure to within 6 psi of that measured in the laboratory. Another case study integrates accurate relative asphaltene gradients into an existing reservoir fluid study to prove reservoir connectivity across a large lateral distance in a producing field. Application of the dual packer subsystem demonstrates inflation within four minutes and pure oil samples within 90 minutes on station in a 1.5-md/cp fractured basement formation. The fine pump control at a low rate enabled sampling just below reservoir pressure in Alaska and a case from the Gulf of Mexico demonstrates the real-time impact of fluid properties on the understanding of reservoir architecture and completion design.
The presented examples highlight the impact of downhole automation, define the new operating envelope for formation testing in the most challenging environments, and highlight how the technology development leads to decision making on a broad reservoir scale by providing contextual answers rather than an accumulation of facts and figures.
Fluid geodynamics processes can alter the hydrocarbon accumulation in the reservoir and complicate the fluid distribution. The processes can be one or combination of late gas charging, biodegradation, water washing, spill-fill charging etc. Fault block migration is another geological process can take place after fluid charging, which results in the fluid re-distribution and brings extra challenges for reservoir evaluation. The understanding and evolution of the fluid geodynamics and fault block migration processes become the key to reveal reservoir connectivity, reservoir charging and geological structural evolution.
This paper elaborates a case study from a Talos Energy's discovery in deep-water Gulf of Mexico, Tornado field from Pliocene formation, to illustrate the connectivity analysis cooperating fault block migration and fluid geodynamics. The high-quality seismic imaging delineated the sand bodies in the reservoir with a gross pay of 400 feet. The two wellbores in the main block A and one wellbore in adjacent block C all exhibit two primary stacked sands separated by an intervening shale break. The RFG (Reservoir Fluid Geodynamics) workflow was applied to this field for connectivity analysis, with integration of the advanced DFA (Downhole Fluid Analysis) data from wireline formation testing, advanced analytical and geochemical analysis of the oil, laboratory PVT and fluid inclusion testing data. The advanced DFA data includes fluid color (asphaltene), composition, Gas-Oil-Ratio (GOR), density, viscosity, and fluorescence yield to help assess connectivity in real-time and after laboratory analysis, which helped to optimize data acquisition and allow the early completion decisions. The DFA data was analyzed using the Flory-Huggins-Zuo Equation of State for asphaltene gradients and the Cubic Equation of State for GOR gradients. The resulting DFA-RFG analysis shows that in the main block A, the fluids in the upper and lower sands are separately equilibrated, in spite of the young age of the reservoir, indicating there is good lateral connectivity in each sand. The asphaltene content of the oil in the upper sand is slightly, yet significantly smaller, than that in the lower sand indicating that the intervening shale might be a laterally extensive baffle or possibly a barrier. Subtleties in the DFA data are more consistent with the shale being a baffle. Moreover, the biomarker analysis shows that all oils encountered are indistinguishable from a petroleum system perspective. This reinforces the DFA-RFG interpretation. However, seismic imaging shows that the intervening shale is not present at the half lower section of the reservoir. With guidance from RFG connectivity analysis, it is consistent with the geology understanding that the shale becomes thinner which beyond the seismic resolution. The paleo flow analysis based on high definition borehole images integrated with seismic interpretation confirmed that upper sand scoured away the intervening shale. The deposition modeling supports that the shale is a baffle.
The sands from the well in the adjacent block C show a vertical shift of asphaltene distribution from block A. The extent of the 360feet vertical offset matches the fault throw from seismic imaging and from log correlation. The fluid properties including asphaltene content, API gravity, methane carbon isotope, GOR, density, are all consistent with the fault block migration scenario. A further complexity is that the upper fault block received a subsequent charge of primary biogenic gas after fault throw. This innovated approach provides guidelines for geophysical and geological interpretation regarding fault block migration and the hydrocarbon charging sequence. The field connectivity conclusions have been confirmed by over 1-year of production history to date.
Petroleomics is the prediction of all properties of petroleum based on the Petroleome, or complete listing of all components in a given crude oil. As it is developed, petroleomics will lead petroleum science into a bright new future, and it is the major focus of this book. A necessary step has been to resolve the molecular size and structure of asphaltene and its hierarchical aggregate structures, as well as the dynamics of asphaltenes. This is especially important for heavy oils. Flow assurance concerns and interfacial science are also treated. The technological development of downhole fluid analysis addresses the most important issues in deepwater production of oil.
Petroleum science and technology are treated in a vertically integrated manner. This book is indispensable for the scientist concerned with petroleum, heavy oils, interfacial science, or flow assurance. Science and technology are treated seamlessly; thus this book will also greatly benefit technologists who are concerned with the production of oil, refining of oil, or heavy oil processing.
Reservoir architecture and the size and reservoir quality of producing bodies remain a central concern particularly in deepwater. In this case study, high-quality seismic imaging delineated the sand bodies and an intervening shale break between two stacked sands. Wireline evaluation in each well consisted of advanced DFA (Downhole Fluid Analysis), formation sampling and pressure measurements, borehole imaging and petrophysics. Reservoir fluid geodynamic analysis of Wireline asphaltene gradient measurements indicate that each sand body is laterally connected and that the shale break could be a baffle. Geodynamic analysis of reservoir architecture employing seismic analysis and wellbore imaging and petrophysical logging concludes the same. All other PVT and geochemical data are compatible with this assessment; nevertheless, the DFA-measured asphaltene gradients are shown to be superior to all other fluid measurements to determine reservoir architecture. The concurrence of high-resolution seismic imaging with advanced wireline for both formation and reservoir fluid geodynamics enables building robust geologic models populated with the accurate fluid structures of the reservoir. History matching months of production match most probable reservoir realizations which are now the basis of reservoir simulation. Future exploration with step-out wells are being optimized with this powerful workflow.
Heavy oil molecular mixtures were investigated on the basis of single molecules resolved by atomic force microscopy. The eight different samples analyzed include asphaltenes and other heavy oil fractions of different geographic/geologic origin and processing steps applied. The collected AFM data of individual molecules provide information about the molecular geometry, aromaticity, the content of non-hexagonal rings, typical types and locations of heterocycles, occurrence, length and connectivity of alkyl side chains and ratio of archipelago- versus island-type architectures. Common and distinguishing structural motifs for the different samples could be identified. The measured size distributions and the degree of unsaturation by scanning probe microscopy is consistent with mass spectrometry data presented herein. The results obtained reveal the complexity, properties and specifics of heavy oil fractions with implications for upstream oil production and downstream oil processing. Moreover, the identified molecular structures form a basis for modeling geochemical oil formation processes.
Characterization of complex reservoirs with multiple fault blocks is critical, especially in deepwater fields where an accurate description of sand continuity and fluid connectivity across fault blocks significantly impacts reserve assessment and production planning. In this paper, a new methodology based on the distribution of reservoir fluid properties, especially asphaltene gradients, is developed to reveal details of reservoir structure and geological history. To our knowledge, this is the first study using asphaltene gradients to track fault-block migration and thereby represents an important new capability of fluid analysis for reservoir characterization. Depending on the reservoir charging history (sequence of heavy/light oils and gases), the asphaltene content of reservoir fluids is typically not in equilibrium at the initial charging stage. After charging, asphaltenes tend to equilibrate by mass flux through permeable connected sands so that the asphaltenes exhibit a smooth and equilibrated gradient. In isolated sand packages, or those with barriers or tortuous connectivity, asphaltenes remain in disequilibrium, often exhibiting abrupt changes. Furthermore, during or after fluid equilibration, subsequent geological events such as faulting and folding may occur, resulting in displacement of fault blocks with their fluids. After faulting, originally equilibrated asphaltenes may exhibit a disequilibrium gradient across isolated fault blocks. On the other hand, fluid and asphaltene can re-equilibrate over juxtaposed sands that became newly connected after faulting. Therefore, fluid distributions are impacted by sand connectivity in current reservoir architecture as well as geological dynamic history. The method applied in this paper uses an Equation of State (EoS) to assess asphaltene equilibrium, which is measured with a downhole fluid analysis (DFA) technique with high resolution and accuracy. An illustrative field study demonstrates how this method can provide insight into detailed reservoir structure, which improves accuracy of cross-section plot with reliable sand connectivity for improved production planning and field management.
Petroleum is one of the most precious and complex molecular mixtures existing. Because of its chemical complexity, the solid component of crude oil, the asphaltenes, pose an exceptional challenge for structure analysis, with tremendous economic relevance. Here, we combine atomic resolution imaging using atomic force microscopy (AFM) and molecular orbital imaging using scanning tunnelling microscopy (STM) to study more than one hundred asphaltene molecules. The complexity and range of asphaltene polycyclic aromatic hydrocarbons (PAHs) are established in detail. Identifying molecular structures provide a foundation to understand all aspects of petroleum science from colloidal structure and interfacial interactions to petroleum thermodynamics, enabling a first-principles approach to optimize resource utilization. Particularly, the findings contribute to a long-standing debate about asphaltene molecular architecture. Our technique constitutes a paradigm shift for the analysis of complex molecular mixtures, with possible applications in molecular electronics, organic light emitting diodes and photovoltaic devices.
Production of crude oil from subsurface reservoirs is greatly impacted by many complexities such as reservoir fluid flow, connectivity, viscosity gradients, and tar mat formation. In situ fluid analysis in oil wells has enabled facile measurement of fluid gradients of dissolved gases and dissolved solids in reservoir crude oils; these gradients have proven very useful for analysis of reservoir complexities. The analysis of solution gas generally uses the cubic equation of state. However, until recently, there had been no predictive equation of state to model asphaltene gradients. Recently, the different nanostructures of asphaltenes in crude oil have largely been resolved and codified in the Yen-Mullins model. In turn, this has enabled equation of state development for asphaltene gradients in crude oils. For example, the Flory-Huggins-Zuo EoS is now ubiquitously utilized in modeling asphaltene gradients. Here, the magnitude and dependencies of the three terms of this EoS, gravity, solubility, and entropy, are considered in detail. Simple expressions for ratios of these terms are obtained as a function of the gas/oil ratio of the crude oils. In particular, the transition from gravity dominance to solubility dominance is examined. A variety of heuristics are developed to guide interpretation of asphaltene gradients that are so routinely measured. Expressions are given that could be used for real-time interpretation upon measurement of these gradients. The utility of EoS modeling of asphaltene gradients is significantly enhanced when incorporating these heuristics.
Recent advances in the understanding of the molecular and colloidal structure of asphaltenes in crude oils are codified in the Yen–Mullins model of asphaltenes. The Yen–Mullins model has enabled the development of the industry’s first asphaltene equation of state for predicting asphaltene concentration gradients in oil reservoirs, the Flory–Huggins–Zuo equation of state (FHZ EOS). The FHZ EOS is built by adding gravitational forces onto the existing Flory–Huggins regular solution model that has been used widely to model the phase behavior of asphaltene precipitation in the oil and gas industry. For reservoir crude oils with a low gas/oil ratio (GOR), the FHZ EOS reduces predominantly to a simple form, the gravity term only, and for mobile heavy oil, the gravity term simply uses asphaltene clusters. The FHZ EOS has successfully been employed to estimate the concentration gradients of asphaltenes and/or heavy ends in different crude oil columns around the world, thus evaluating the reservoir connectivity, which has been confirmed by the subsequent production data. This paper reviews recent advances in applying the FHZ EOS to different crude oil reservoirs from volatile oil (condensate) to black oil to mobile heavy oil all over the world to address key reservoir issues, such as reservoir connectivity/compartmentalization, tar mat formation, non-equilibrium with a late gas charge, and asphaltene destabilization. The workflow incorporates the integration of new technology, downhole fluid analysis (DFA), coupled with the new scientific advances, the FHZ EOS and Yen–Mullins model. The combination proves a powerful new method of reservoir evaluation. Asphaltene or heavy end concentration gradients in crude oils are treated using the FHZ EOS, explicitly incorporating the size of resin molecules, asphaltene molecules, asphaltene nanoaggregates, and/or asphaltene clusters. All of the parameters in the FHZ EOS are related to DFA measurements, such as compositions, GOR, density, etc. The variations of gas and oil properties with depth are calculated by the classical cubic equation of state (EOS) based on DFA compositions and GOR using specifically developed delumping, characterizing, and oil-based drilling mud (OBM) contamination correcting techniques. Field case studies have proven the value and simplicity of this asphaltene or heavy end treatment. Heuristics can be developed from results corresponding to estimation of asphaltene gradients. Perylene-like resins with the size of 1 nm are dispersed as molecules in high-GOR volatile oils with high fluorescence intensity and virtually no asphaltenes (0 wt % asphaltene). Heavy asphaltene-like resins with the size of 1.3 nm are molecularly dissolved in volatile oil at a very low asphaltene content. Asphaltene nanoaggregates with the size of 2 nm are dispersed in stable crude oil at a bit higher asphaltene content. Asphaltene clusters are found in mobile heavy oil with the size of 5 nm at even higher asphaltene content (typically >8 wt % based on stock tank oil). Two types of tar mats are identified by the FHZ EOS: one with a large discontinuous increase in asphaltene content versus depth typically at the base of an oil column (corresponding to asphaltene phase transition) and one with a continuous increase in asphaltene content at the base of a heavy oil column simply by extending the oil column in the downdip direction because of an exponential increase in viscosity with asphaltene content. All of these studies are in accordance with the observations in the Yen–Mullins model within the FHZ EOS analysis.
The rotational correlation times of individual asphaltene molecules have been determined using fluorescence depolarization techniques, addressing an active, long-standing controversy. Using simple theoretical models and using model-independent comparisons with known chromophores, a range of asphaltene molecular diameters is obtained of 10−20 Å. Comparison with corresponding data of known chromophores indicates a molecular mass for asphaltene molecules of 500−1000 amu. Furthermore, we have performed the first direct measurement correlating molecular size with constituent chromophore size; we establish that the bulk of asphaltene molecules possess 1 or 2 (aromatic) chromophores per molecule. Similar results are found for the largest aromatic molecules of the de-asphaltened crude oil.
Fluorescence depolarization measurements are used to determine the size of asphaltene molecules and of model compounds for comparison. Mean molecular weights of roughly 750 amu with a range of roughly 500−1000 amu are found for petroleum asphaltenes. A strong correlation is established between the size of an individual fused ring system in an asphaltene molecule and the overall size of this corresponding molecule, showing that asphaltene molecules have one or perhaps two fused ring systems per molecule. Subtle differences in molecular size are found for different virgin crude oil asphaltenes and for a vacuum resid asphaltene. Coal asphaltene molecules are found to be much smaller than petroleum asphaltenes. The molecular sizes of resins and asphaltenes are found to form a continuous distribution.
Asphaltene molecular weight ( Asphaltenes, Heavy Oils and Petroleomics; Springer: New York, 2007) continues to be the subject of a longstanding debate in the literature. A paper ( Energy Fuels2007, 21, 2176−2203) recently published (referred to as HBK) claims that asphaltene molecular weights are bimodal with one component in the roughly megadalton range and a second component in the roughly 5 kDa range. These claims are in sharp contrast to results published from a variety of measurements with the overall conclusions that asphaltene molecular weights are monomodal with a most probable 750 Da (±200) with a fwhm 500–1000 Da. In this report, we provide a summary of the four molecular diffusion techniques and seven mass spectral techniques from many groups around the world that are all in accord with the 750 Da most probable mass. Moreover, here we discuss why HBK reported anomalously large asphaltene molecular weights along with the unique claim of a bimodal distribution. In particular, the size exclusion chromatography (SEC) results that yield megadalton masses were performed with the solvent N-methylpyrrolidinone which is known to flocculate up to 50% of the asphaltenes. The megadalton mass is likely large asphaltene aggregates or flocs. In a previous referenced paper from the HBK labs, the better solvent for asphaltenes, tetrahydrofuran, did not give the megadalton peak in their SEC experiments as they stated; we suspect because the asphaltenes were suitably dissolved (although still with some aggregation). The corresponding discussion treats the known hierarchy of asphaltene aggregation at very low concentration in a good solvent, toluene. In addition, the mass spectral method used in HBK, laser desorption ionization, is shown herein and in the literature to yield anomalously large molecular weights for asphaltenes and polycyclic aromatic hydrocarbons due to gas phase aggregation if (1) the laser power is too high, (2) the surface concentration of asphaltenes is too high, or (3) if the ions are collected too quickly (i.e., from a dense plasma). Properly accounting for these potential pitfalls, one obtains the same most probable ~750 Da molecular weight as from all of the other techniques. Finally, ESI MS is shown herein and in ample literature to be readily able to detect large masses (the primary reason ESI led to a Nobel Prize); the absence of large mass species in ESI MS of asphaltenes is because they are not present. The congruence of so many molecular diffusion techniques and mass spectral techniques is a powerful advance for asphaltene science.
The modeling of hydrocarbon fluids in oil-field reservoirs is essential for optimizing production. In particular, the often large compositional variations of reservoir crude oils must be understood and modeled. The two most important chemical constituents that govern many chemical and physical properties of subsurface reservoir crude oils are the dissolved gas content, described by the gas−oil ratio (GOR), and the asphaltene content. The modeling of GOR variations of crude oils in reservoirs has been practiced routinely for many decades. However, proper modeling of the asphaltenes and/or heavy ends of reservoir crude oils has been precluded because of the lack of understanding of the chemical and physical properties of asphaltenes in crude oils. Recently, the modified Yen model has codified advances in asphaltene science by providing a framework for understanding the molecular and colloidal structure of asphaltenes in crude oils. Here, a thermodynamic model of asphaltenes in reservoir crude oils is developed that can incorporate the modified Yen model and thus can be used to treat reservoir crude oils. Our objective is to analyze the distribution of reservoir fluids, in particular the asphaltenes. This deviates from most previous studies of asphaltene thermodynamics, which were focused on the phase behavior of asphaltenes. Here, compositional gradients of asphaltenes, as well as the GOR of reservoir crude oils, are analyzed. Asphaltene gradients are shown to be strongly affected by both gravity and solubility. The latter effect is heavily dependent on the dissolved gas content of the reservoir crude oil. Case studies are provided that exhibit the power of this modeling.
Asphaltenes are defined in terms of their solubility classification. This operational definition combined with the previous controversy over asphaltene molecular weight have obscured the governing chemical and structural parameters that define the asphaltene fraction. Here, asphaltenes are investigated by several techniques to elucidate relations between structure and properties. In particular, the asphaltene molecular size is compared to the ratio of aromatic to saturated carbon. The conclusion is obtained that asphaltene molecular structure is governed by the balance between the propensity of fused aromatic ring systems to stack via π-bonding, reducing solubility, vs the steric disruption of stacking due alkane groups, increasing solubility.
Ultrahigh-resolution Fourier transform ion cyclotron resonance mass spectrometry has recently revealed that petroleum crude oil contains heteroatom-containing (N,O,S) organic components having more than 20,000 distinct elemental compositions (C(c)H(h)N(n)O(o)S(s)). It is therefore now possible to contemplate the ultimate characterization of all of the chemical constituents of petroleum, along with their interactions and reactivity, a concept we denote as "petroleomics". Such knowledge has already proved capable of distinguishing petroleum and its distillates according to their geochemical origin and maturity, distillation cut, extraction method, catalytic processing, etc. The key features that have opened up this new field have been (a) ultrahigh-resolution FT-ICR mass analysis, specifically, the capability to resolve species differing in elemental composition by C(3) vs SH(4) (i.e., 0.0034 Da); (b) higher magnetic field to cover the whole mass range at once; (c) dynamic range extension by external mass filtering; and (d) plots of Kendrick mass defect vs nominal Kendrick mass as a means for sorting different compound "classes" (i.e., numbers of N, O, and S atoms), "types" (rings plus double bonds), and alkylation ((-CH(2))(n)) distributions, thereby extending to >900 Da the upper limit for unique assignment of elemental composition based on accurate mass measurement. The same methods are also being applied successfully to analysis of humic and fulvic acids, coals, and other complex natural mixtures, often without prior or on-line chromatographic separation.
Defined by their solubility in toluene and insolubility in n-heptane, asphaltenes are a highly aromatic, polydisperse mixture consisting of the heaviest and most polar fraction of crude oil. Although asphaltenes are critically important to the exploitation of conventional oil and are poised to rise in significance along with the exploitation of heavy oil, even as fundamental a quantity as their molecular weight distribution is unknown to within an order of magnitude. Laser desorption/ionization (LDI) mass spectra vary greatly with experimental parameters so are difficult to interpret: some groups favor high laser pulse energy measurements (yielding heavy molecular weights), arguing that high pulse energy is required to detect the heaviest components of this mixture; other groups favor low pulse energy measurements (yielding light molecular weights), arguing that low pulse energy is required to avoid aggregation in the plasma plume. Here we report asphaltene mass spectra recorded with two-step laser mass spectrometry (L2MS), in which desorption and ionization are decoupled and no plasma is produced. L2MS mass spectra of asphaltenes are insensitive to laser pulse energy and other parameters, demonstrating that the asphaltene molecular weight distribution can be measured without limitation from insufficient laser pulse energy or plasma-phase aggregation. These data resolve the controversy from LDI, showing that the asphaltene molecular weight distribution peaks near 600 Da and previous measurements reporting much heavier species suffered from aggregation effects.
The Modified Yen Model.Energy and Fuels
- Mullins
The Physics of Reservoir Fluids: Discovery Through Downhole Fluid Analysis
- Mullins