Garcia, German D. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Mishra, Vinay (Schlumberger) | Chen, Li (Schlumberger) | Hayden, Ron (Schlumberger) | Babin, Christopher (Schlumberger) | Cig, Koksal (Schlumberger)
A concept platform integrating the precise movement of a linear or azimuthal actuator, such as in instrumented wireline intervention tools (IWIT), with fast pressure measurement and/or rock sampling instruments is presented. This device accurately moves the measurement probe or sampling assembly either in the longitudinal or azimuthal direction in the wellbore to significantly improve operational efficiency and data quality.
Precise movement control enables acquiring data at exact intervals to eliminate errors induced by cable stretching, overpull, or variable cable creep. Specific lithofacies can be targeted from a borehole image log. Simulation with current IWIT capabilities shows significantly reduced uncertainty over common wireline protocols. The operational procedure includes correlation using standard wireline gamma ray methods. The platform is anchored at the top of the zone of interest and a distributed survey made with the linear actuator for every probe displacement. Removing cable movement significantly reduces an important source of error in distributed pressure measurement. A similar approach is proposed for the coring tool with the added benefit of being able to rotate the tool's bit at different azimuths to collect rock samples.
This concept platform would enable reducing the time spent on pressure surveys if similar accuracy to current standard practices is acceptable. Because the only remaining source of error is gauge accuracy, results show that fewer stations are necessary to replicate standard wireline results. Where accuracy is important, as with distributed pressure measurements to quantify reserves using gradient intersection to define fluid contacts or determine compositional gradients, the proposed approach is shown to significantly reduce error using the same number of stations. We use data sets from previous work to show the impact of the error reduction in the position of the fluid contact.
IWITs currently used in cased hole employ active anchoring to perform intervention tasks, including linear actuators capable of delivering up to 80,000 lbf of stroking force. In the proposed concept platform, this pulling force could be instrumental where there is high risk of differential sticking. By anchoring the upper part of the platform in overlying impermeable intervals, the probe could be lowered into the permeable interval to conduct the pressure survey or fluid or rock sampling operation without exposing the full length of the platform to the pressure differential forces for significant risk mitigation.
The proposed architecture for the concept platform innovatively combines several operational concepts used today as separate entities in wireline operations. Their integration, however, generates important efficiency gains, reduces the risk in stationary measurements and operations, improves accuracy, and enables the implementation of unprecedent distributed pressure measurements and coring practices with azimuthal rotational capabilities using wireline.
Mullins, Oliver C. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Chen, Li (Schlumberger) | Achourov, Vladislov (Schlumberger) | Meyer, John (Deep Gulf Energy) | Johansen, Yngve Bolstad (AkerBP) | Rinna, Joachim (AkerBP) | Winkelman, Ben (Talos) | Wilkinson, Tim W. (Talos) | di Primio, Rolando (Lundin) | Elshahawi, Hani (Shell) | Canas, Jesus (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y. (Schlumberger)
Asphaltenes can be dispersed in crude oils in 3 different forms; molecules, nanoaggregates (of molecules) or clusters (of nanoaggregates); these forms are codified in the Yen-Mullins model and relate to the extent of solvency of the asphaltenes in the crude oil. Many reservoir studies are used here to show the systematic behavior of the specific asphaltene species in crude oil and the corresponding magnitude of the asphaltene (and viscosity) gradients. In addition, the specific asphaltene species is related to the chemical origin controlling asphaltene onset pressure (AOP) and tar formation and depends on 1) the quality of the live crude oil solvent for asphaltenes and 2) the concentration of asphaltenes. Elevated quantities of solution gas of a reservoir crude oil significantly reduce the solvency of asphaltenes in crude oil. For low concentrations and/or good solvency, asphaltenes are dispersed in crude oils as molecules with small gradients (unless there are large GOR gradients). For moderate concentrations and/or moderate solubility, asphaltenes are dispersed as nanoaggregates with intermediate (gravity) gradients of asphaltenes. With large concentrations and/or poor solvency, asphaltenes are dispersed as clusters with very large gradients in reservoirs. These crude oils can also exhibit higher asphaltene onset pressures and/or phase separated bitumen or tar in the reservoir depending on the origin of asphaltene cluster formation. Secondary gas charge into oil reservoirs can yield tar and/or a high AOP. The effect of biodegradation on these factors is also discussed. The systematics presented here are helpful in understanding a variety of reservoir concerns associated with asphaltenes.
Mullins, Oliver C. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Mishra, Vinay K. (Schlumberger) | Gomez, Alexandra (Chevron) | Wilkinson, Tim (Talos) | Winkelman, Ben (Talos) | Primio, Rolando Di (Lundin) | Uchytil, Steven (Hess) | Nagarajan, Nagi (Hess) | Strauss, Steve (Hess) | O'Donnell, Martin (Premier) | Seifert, Douglas J. (Saudi Aramco) | Elshahawi, Hani (Shell) | Chen, Li (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav (Schlumberger) | Zeybek, Murat (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Forsythe, Jerimiah (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Andrews, A. Ballard (Schlumberger) | Pomerantz, Andrew E. (Schlumberger)
Reservoir fluid geodynamics (RFG) has recently been launched as a formal technical arena that accounts for fluid redistributions and tar formation in reservoirs largely after trap filling. Elements of RFG, such as analysis of biodegradation, have long been in place; nevertheless, RFG is now strongly enabled by recent developments: 1) downhole fluid analysis (DFA) allows routine elucidation of reservoir fluid gradients, 2) the development of the first equation of state for asphaltene gradients allows identification of equilibrium vs. geodynamic processes of reservoir fluids and 3) RFG analyses of 35 oilfields systematize a multitude of RFG processes and show their direct impact on wide-ranging production concerns. Thermodynamic analyses identifying reservoir fluid geodynamic processes rely heavily on measurement of fluid gradients to avoid ambiguous interpretations. The unique role of asphaltene gradients and their integration with other data streams are the focus herein.
RFG oilfield studies have repeatedly shown that analyses of asphaltene gradients are critical to proper evaluation of RFG processes. Naturally, any reservoir concern that directly involves asphaltenes such as heavy oil, viscosity gradients, asphaltene onset pressure, bitumen deposition, tar mat formation, and indirectly, GOR gradients are strongly dependent on asphaltene gradients. Moreover, as shown in numerous case studies herein, asphaltene gradients can be measured with accuracy and the corresponding thermodynamic analyses allow explicit identification of RFG processes not traditionally associated with asphaltenes, such as analysis of connectivity, fault block migration, baffling, spill-fill mechanisms and many others discussed below. In turn, these processes imply other corroborative reservoir and fluid properties that can then be confirmed.
Crude oil chemical compositional data, such as ultrahigh resolution two-dimensional gas chromatography, combined with geochemical interpretation, is highly desirable for understanding RFG processes. Nevertheless, biomarkers and other fluid properties often exhibit small gradients relative to standard deviations (except with biodegradation) but often can still corroborate specific RFG processes. In general, integration of fluid gradient analysis with other data streams including petrophysics, core analysis, stratigraphy, geology and geophysics is critical; nevertheless, which integration is most needed depends on particular reservoir attributes and RFG processes that are in question. Examples of data integration are shown for ten reservoirs undergoing various fluid geodynamic processes. Asphaltene gradient analysis is relatively new, yet it is essential for characterization of RFG processes.
Zuo, Julian Y. (Schlumberger) | Pan, Shu (Schlumberger) | Wang, Kang (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Elshahawi, Hani (Shell) | Canas, Jesus A. (Schlumberger) | Chen, Li (Schlumberger) | Dumont, Hadrien (Schlumberger) | Mishira, Vinay K. (Schlumberger) | Garcia, German (Schlumberger) | Jackson, Richard (Schlumberger)
The Flory-Huggins-Zuo equation of state (FHZ EOS) was developed based on downhole fluid analysis (DFA) measurements and the Yen-Mullins model to delineate equilibrium asphaltene gradients and reservoir connectivity. However, dynamic processes are often observed in reservoirs, and these cause nonequilibrium fluid distributions. Gas charges into reservoirs can result in asphaltene flocculation, formation damage, and/or tar mat formation, which significantly impact reservoir architectures and field development planning. Therefore, it is important to understand and simulate reservoir fluid geodynamic processes. In this work, a new reservoir fluid geodynamic model is proposed to quantitatively study asphaltene distributions over geological time. The model has shown a great potential to bring an insightful understanding of history and architectures of petroleum reservoirs.
The diffusion model is developed for multicomponent systems in the framework of the generalized Maxwell-Stefan mass transfer theory. Moreover, to account for asphaltene migration, diffusion, Stokes falling, and advective currents are all considered. In addition, to take into account the fact that asphaltenes exist as nanoaggregates and clusters, an engineering approach is proposed to simplify the generalized Maxwell-Stefan theory by lumping two asphaltene gravitational terms. Advection is taken into account by buoyancy velocity induced by density inversion that is created upstructure in reservoirs during density stacking of gas charge into oil. A numerical solver is applied to solve the asphaltene migration equations with relevant boundary conditions.
This model has been applied to two case studies. The first case is a hypothetical reservoir in which a significant density inversion forms during the gas charge, which induces (rapid) gravity currents (advection). The evolution of the asphaltene migration and present day distribution in this reservoir is simulated by considering all these complexities. The second case study is based on an actual reservoir under active gas charging. In this case, no dominant density inversion was observed in simulation using the diffusion model either with or without the gravity term. The results from the new model with the Stokes sedimentation term for asphaltene clusters show an excellent agreement with the field observations and superior to the simulated results without gravitational forces.
In summary, this new reservoir fluid geodynamic model has quantitatively described the asphaltene migration driven by not only diffusion in a concentration gradient but also Stokes falling and advection in a gravitational field. The gravitational terms of two forms of asphaltenes are well approximated by a new lumping approach. This work quantifies asphaltene migration using diffusion, Stokes falling and advection, all with crucial contributions during gas or light hydrocarbon charge into oil reservoirs.
Dumont, Hadrien (Schlumberger) | Garcia, German (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Nighswander, John (Schlumberger) | Mishra, Vinay K. (Schlumberger) | El-Khoury, Jules (Schlumberger) | Chen, Li (Schlumberger) | Lake, Patrick (Schlumberger)
AbstractDeepwater fields, such as those encountered in the Gulf of Mexico (GoM), often exhibit reservoir tar deposits and asphaltene instability (Dumont et al, 2012, Mullins et al, 2016). This instability may manifest itself within the reservoir in the form of out of equilibrium asphaltene gradients and tar deposits. These tar deposits can present drilling hazards which are a major nuisance for drilling operations, and can force operators to drill multiple sidetracks or bypass wells. This of course leads to increase well spend and rig time usage. For instance, the last two years showed that approximately 5% of the wells drilled in the GoM encountered severe drilling issues related to asphaltenes/tar deposits. Even more critical and concerning, is that asphaltene instability can have major implications for field developments, stretching expenditure risks beyond a single well to that of an entire field.From a flow assurance point of view, comingling incompatible oil produced from different zones or reservoirs can precipitate, and worse, deposit asphaltenes in the production path even when the unmixed oils are individually stable. Thus for reservoir management and field development plan, tar deposits can seal off aquifer support and have a detrimental impact on the productivity index of the field. During field development planning, it is essential to know the Asphaltene Onset Pressure (AOP) of the produced oils at reservoir conditions and its change with pressure and temperature along the wellpath. In addition, for unstable oils, AOP gradients variations across the field should be evaluated as AOP can vary largely as a result of Reservoir Fluid Geodynamics (RFG) processes occurring within the reservoir. For instance, fluid mixing due to a secondary charge into a reservoir after trap filling increases the AOP of the resulting oil. In addition, the non-homogeneity of AOP can then be mislabeled as AOP laboratory uncertainty. As AOP field variability can impact all aspects of the journey of the oil to surface, (well placement, completion, recovery factor, injection for pressure support, surface facility, and subsea equipment) and because no model exist to predict AOP gradients, the measurement and the evaluation of these AOP gradients, coupled with simple chemistry understanding are key inputs to a successful field development plan. This paper discuss AOP gradients within a reservoir, their impact on Field Development Plan (FDP), their origin, and proposes a methodology to characterize them.
Mullins, Oliver C. (Schlumberger) | Primio, Rolando Di (Lundin) | Zuo, Julian Y. (Schlumberger) | Uchytil, Steve (Hess) | Mishra, Vinay K. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav V. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Forsythe, Jerimiah (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Elshahawi, Hani (Shell)
Petroleum system modeling provides the timing, type and volume of fluids entering a reservoir, among other things. However, there has been little modeling of the fluid processes that take place within the reservoir in geologic time, yet these processes have a dramatic impact on production. Modeling and understanding of the reservoir then reinitiates with simulation of production for optimization purposes. The new discipline "reservoir fluid geodynamics" (RFG) establishes the link between the petroleum system context or modeling and present day reservoir realizations. This new discipline has been enabled by scientific developments of the new asphaltene equation of state and by the technology of downhole fluid analysis (DFA). Gas-liquid equilibria are treated with the traditional cubic EoS. Crude oil fluid- asphaltene equilibria are treated with the Flory-Huggins-Zuo equation of state with its reliance on the Yen-Mullins model of asphaltenes. Thermodynamic treatment is essential in order to identify the extent of equilibrium in oil columns, thereby identifying fluid dynamics in geologic time. DFA is shown to be very effective for establishing asphaltene gradients vertically and laterally in reservoir fluids with great accuracy. In turn, this data tightly constrains the thermodynamic analyses. These methods have been applied to a large number of reservoir case studies over a period of ten years. For example, case studies are shown that indicate baffling and lower production for parts of the reservoir that have slower rates of fluid equilibration. In addition, the newly revealed lateral sweep in trap filling is established via RFG case studies. Underlying systematics, especially for gas charge into oil reservoirs, have been revealed for a large number of fluid and tar distributions that enable a unifying and simplified treatment for seemingly intractable complexities. A case study is presented that shows three very different reservoir realizations in adjacent fault blocks for the same petroleum system model, where RFG explains all these differences. This enables key reservoir properties to be projected away from wellbore in ways not previously possible. Finally, universal work flows are shown which enable broad application of these methods through all phases of reservoir exploration and production.
Mullins, Oliver C. (Schlumberger) | Primio, Rolando Di (Lundin) | Uchytil, Steve (Hess) | Zuo, Julian Y. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Mishra, Vinay (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav (Schlumberger)
Deposition of organic solids high in asphaltene content (tar, bitumen) in reservoirs from natural processes is a routine occurrence around the world. Nevertheless, there is a bewildering array of deposition characteristics as shown in recent case studies. Sometimes this tar or bitumen (both are really the same material) is at or near the crest; sometimes it is on interlayers within a heterolithic sequence (baffles) or at the base of the reservoir which can be tens of kilometers away from the crest. Sometimes the bitumen deposition is such that the corresponding formation remains permeable; sometimes the tar zone is totally impermeable. Sometimes the tar at the base of the reservoir represents a more or less continuous increase in asphaltenes from the oil immediately above the tar; sometimes there is a sharp, discontinuous increase in asphaltene content from the oil to the tar. And particularly for upstructure bitumen, sometimes the bitumen is deposited throughout the entire producing interval (in a well); at other times the bitumen deposition is only at the base of the producing interval. This paper shows that ALL of these variable tar or bitumen characteristics can be understood within simple concepts that treat the dissolved asphaltene in crude oils and the deposited asphaltene within the same framework. This framework utilizes simple chemical solution characterisitcs that are formally expressed in the Flory-Huggins-Zuo Equation of State for asphaltene gradients with its reliance on the Yen-Mullins model of asphaltenes. Multiple charges of incompatible fluids lead to asphaltene deposition. The extent of slow, diffusive destabilization from density stacking charge fluids versus rapid destabilization from a secondary lateral fluid front controls much of the characteristics of deposited asphaltene. Consequently, the proximity of the well to reservoir charge points as well as petrophysical parameters of the formations are very important parameters. The ideas herein enable projection of the nature of asphaltene deposition away from a wellbore to other locations in the reservoir. This capability greatly assists the ability to understand the impact of asphaltene deposition on production.
Mullins, Oliver C. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Mishra, Vinay (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y (Schlumberger) | Tilke, Peter (Schlumberger) | Elshahawi, Hani (Shell) | Di Primio, Rolando (Lundin)
Currently, the understanding and modeling of reservoir geological structures incorporate the depositional setting and subsequent burial, diagenesis, and deformation. It is unimaginable to proceed in reservoir development without extensive knowledge of this geologic history. However, the complete interpretation of these reservoirs also behooves an understanding of the fluid evolution following migration into the trap. This paper provides an overview of the significant deficiency that, until now, has persisted with regard to the evolution of reservoir fluids. In contrast to geological structures, reservoir crude oils have been modeled and understood only within the context of what fills the reservoir, with very little modeling or understanding of fluid (and tar) alterations that occur subsequent to reservoir entrapment.
A demonstration of this deficiency is illustrated by current petroleum system modeling (PSM) workflows that provide, among other things, the timing, type, and volume of fluids that enter the reservoir. However, there are no (commercial) software packages that provide insight on the evolution of reservoir fluids by diffusion, convection and (asphaltene) phase behavior over geologic time following their entrapment in the reservoir. We describe these diverse phenomena as “Reservoir Fluid Geodynamics” (RFG), which refers to the time period after reservoir filling and before present day (or production); that is, “RFG is between reservoir fill and drill”. Like deposition, diagenesis and deformation, RFG processes occur at geologic time scales and can be as short as 1 million years (Ma) as seen under the continental shelf of Norway, or as long as 100 Ma as in the presalt of Brazil. In these two examples, and many other cases, the impact of RFG processes on production is profound. Our current understanding of RFG processes has already benefited from the development of the Flory-Huggins-Zuo Equation of State with its reliance on the Yen-Mullins model of asphaltenes. However, to fully address RFG, it is required to have a comprehensive scientific foundation, including asphaltene thermodynamics as well as the understanding of diffusive and convective flows in reservoirs. In addition, a complete integration into the reservoir characterization and modeling workflow is required. For example, extensive fluid gradient data is required to unravel RFG processes. Through the ubiquitous use of downhole fluid analysis (DFA), many examples of these gradient data are available and are well suited to thermodynamic modeling. In addition, reservoir case studies are required; ten years of DFA case studies have enabled a systematic classification of RFG processes. This greatly enhanced understanding of reservoir fluids is already impacting efficiency in reservoir valuation, optimization, and field development planning.
Dumont, Hadrien (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Garcia, German (Schlumberger) | Mishra, Vinay K. (Schlumberger) | Harrison, Christopher (Schlumberger) | Fukagawa, Shunsuke (Schlumberger) | Sullivan, Matthew (Schlumberger) | Chen, Li (Schlumberger) | Montesinos, Jordi (Schlumberger) | Robert, Red (Schlumberger)
Copyright 2016, held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. This paper was prepared for presentation at the SPWLA 57th Annual Logging Symposium held in Reykjavik, Iceland June 25-29, 2016. ABSTRACT Deepwater oil reservoirs contain variable amounts of asphaltenes, defined as insoluble in n-C7 and soluble in toluene. These asphaltenes are in nanocolloidal suspension in the oil at reservoir conditions but as pressure and/or temperature change, part of the asphaltenes can precipitate out of solution. The characterization of this phase change (Liquid-Solid) in a pressure-temperature space is challenging due to the following factors: sample availability, sample integrity, laboratory methods, high pressure measurement apparatus, and oil near or at asphaltene onset at reservoir conditions. For example, many reservoirs are at pressures which exceed laboratory capabilities. This paper describes an innovative method to measure Asphaltene Onset Pressure (AOP) using Downhole Fluid Analysis (DFA): the oil from the formation after cleanup is kept in the wireline tool and exposed to a pressure and temperature changes while the tool is pulled out of hole. During these changes in pressure and temperature, the measurements optical spectroscopy, density and viscosity are performed continuously on the oil. Spectroscopy analysis provide the following: DFA AOP measurement by standard methods. Saturation pressure The advantage of this AOP method over laboratory AOP include measurement up to reservoir pressures, minimum sample handling, AOP measurement prior to sample cooling and real time ability to repeat measurements.
Downhole fluid analysis (DFA) has been successfully employed to estimate compositions, gas/oil ratios (GOR), coloration (asphaltene content), density, viscosity and oil-based mud (OBM) filtrate contamination in real time. However, an important element – formation volume factor (FVF), defined as a ratio of the volume of a reservoir fluid at downhole conditions to the volume of stock tank oil at standard conditions – has been missing. This paper presents several real-time methods to obtain FVF from formation tester data and discusses applications of the newly derived fluid property.
A novel method is developed to obtain FVF based on mass balance during a single-stage flash process performed at standard conditions. The required input parameters, including density, GOR, and composition, are all available from existing DFA measurements in real time, ensuring a robust and simple FVF calculation. The new method is compared to a pressure-volume-temperature (PVT) laboratory-derived correlation based on machine learning methods and a method based on an equation of state (EOS) that uses more than 1350 fluid samples covering all hydrocarbon reservoir fluid types. The results show that the prediction error of the new FVF algorithm has an average absolute deviation of 3.6%. A second method, which begins with the definition of FVF and utilizes optical absorbance measurements and estimated fluid composition -- CO2, C1, C2, C3-5, and C6+ -- to derive an equation for the FVF is also demonstrated. The coefficients in this equation are calibrated against an optical spectral library derived from 160 hydrocarbon samples measured at different temperatures and pressures with values up to 175°C and 20,000 psi. The FVF prediction standard error of approximately 2.4 % for this method is estimated by comparing FVF predictions with laboratory measured FVFs on a validation dataset.
The use of the new FVF algorithms in deriving several real time fluid properties is illustrated. For example, FVF is used in OBM filtrate contamination calculations during sample cleanup for focused and non-focused sampling tools and is used to convert live fluid-based OBM filtrate contamination to a stock tank liquid-based value.
Best practices for selecting which FVF algorithm to use are discussed and recommendations for algorithm selection are made. Several case studies detail FVF calculations based on wireline or while-drilling formation tester data and the examples show how FVF is used in other real time DFA workflows. The results obtained from the new methods are in good agreement with results of PVT laboratory sample analysis.