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Collaborating Authors
Fluid Characterization
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)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- (2 more...)
Abstract A Jurrasic oilfield in Saudi Arabia is characterized by black oil in the crest and with mobile heavy oil underneath and all underlain by a tar mat at the oil-water contact. The viscosities in the black oil section of the column are fairly similar and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large continuous increase in asphaltene content with increasing depth extending to the tar mat. The tar shows very high asphaltene content but not monotonically increasing with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from several to ~ 1000 centipoise in the mobile heavy oil and increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. Conventional PVT modeling of this oil column grossly fails to account for these observations. Indeed, the very large height in this oil column represents a stringent challenge for any corresponding fluid model. A simple new formalism to characterize the asphaltene nanoscience in crude oils, the Yen-Mullins model, has enabled the industry's first predictive equation of state (EoS) for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS. For low GOR oils such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the FHZ EoS employing the Yen-Mullins model accounts for the major property variations in the oil column and by extension the tar mat as well. Moreover, as these crude oils are largely equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically improving understanding of important constraints on oil production in oil reservoirs.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.48)
Abstract Many techniques are used in industry to determine reservoir hydraulic connectivity from static data. These can be rock-based techniques such as seismic mapping, well to well correlations and geological modeling. Or they can be fluid based techniques such as pressure and fluid gradients. Fluid pressure gradients acquired with formation testers have long been popular but they are understood to be able to identify a lack of connectivity and cannot necessarily prove the presence of connectivity. Recent work has shown that mapping fluid gradients can be much more definitive. For light fluids this mapping is based on the gas-oil ratio (GOR). For heavier fluids, with little GOR variation, this technique requires mapping a different parameter. It has been suspected that asphaltene content was the parameter to map, but until recently the science of asphaltene prediction was unclear. Recent advances in asphaltene science have now clarified the mechanism for asphaltene distribution in the reservoir and gradient prediction is now possible. And most fortunately it turns out that the asphaltene gradient is relatively easy to measure in-situ. In this paper we present the science behind asphaltene gradient prediction and show how fluid gradients are a superior way to infer reservoir connectivity. We then present data from an Eastern Siberia oilfield where asphaltene gradients are determined in-situ with a wireline formation tester. These gradients are verified by later comparison to laboratory measurements. Finally and most importantly, we show also how the asphaltene content is used to predict reservoir connectivity both vertically and laterally.
- Asia (1.00)
- North America > United States > Texas (0.46)
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)
Integrated Asset Modeling for Reservoir Management of a Miscible WAG Development on Alaska's Western North Slope
Roadifer, R. D. (ConocoPhillips Alaska Inc) | Sauvé, R.. (Schlumberger) | Torrens, R.. (Schlumberger Middle East SA) | Mead, H. W. (ConocoPhillips Alaska Inc) | Pysz, N. P. (ConocoPhillips Alaska Inc) | Uldrich, D. O. (ConocoPhillips Alaska Inc) | Eiben, T.. (ConocoPhillips Canada)
Abstract An integrated asset modeling (IAM) approach has been implemented for the Alpine Field and eight associated satellite fields on the Western Alaskan North Slope (WNS) to maximize asset value and recovery. The IAM approach enables the investigation of reservoir and facilities management options under existing and future operating constraints. Oil, gas and water production from these fields are processed at the Alpine Central Facility (ACF). A number of local constraints exist for the asset, such as the requirement that all associated gas be used for facilities power generation, gas lift or re-injection. All produced water must be re-injected and, for pipeline integrity reasons, must be segregated from imported make-up sea water used for injection. Additionally, surface gas and water handling capacity is limited at the ACF. To further complicate matters, gas injected for EOR purposes is enriched such that it is miscible or near-miscible at reservoir conditions. These conditions create a unique and changing relationship between the oil, gas and water production, gas lift, miscible water alternating gas (MWAG) injection, lean gas injection, facilities constraints and injection availability. The scope of the current IAM project has been multi-fold. Optimization of oil production across all WNS fields requires the placement of injection fluids be simultaneously optimized. The optimization procedure begins by allocation of oil production targets based on current operating conditions, the potentials of the wells in each field to deliver fluids, and total gas lift availability. Excess gas compression capacity is utilized for gas lift and is allocated via an incremental gas-oil ratio sort on the production wells. Given the constraints on water injection noted above, optimization of injection fluids begins by determining pump requirements for produced water and the optimal field or injection manifold placement of the produced water. Following this, optimized placement of the miscible injectant (MI) and lean gas injectant (LGI) is determined based on a dynamic MWAG scheduling methodology developed to maximize oil recovery and ensure the number of gas injection wells have sufficient capacity to inject the required volume of gas in each reservoir. The volumetric split of gas into MI and LGI streams falls out directly from the specification of a target minimum miscibility pressure (MMP) constraint for the MI and the volume of condensates driven off the top of the condensate stabilizer column at the process facility. Finally, the volume of the make-up fluid (sea water) is determined based on the minimum of the remaining pump capacity or potential of the remaining wells to inject the water and allocated to each field based on a fractional oil voidage replacement scheme. Maximizing production across multiple fields necessarily requires that the best player (well) plays, regardless of the field to which it belongs. This requirement relates to both instantaneous production as would be considered under a gas lift optimization scenario as well as the longer term MWAG performance and recovery of each individual well pattern across all the fields. The IAM technology utilized for managing the WNS fields consists of full-field compositional reservoir simulation models for each reservoir integrated with a pipeline surface network model and a process facility model. Spreadsheet based allocation routines and advanced mathematical coupling algorithms complete the IAM model enabling not only the prediction of the assets’ performance under the aforementioned constraints, capacities and operating conditions, but to optimize overall performance and analyze the impact of decisions. To the authors’ knowledge, this is the first time integrated asset modeling has been applied to bring the entire production stream including reservoir, wellbore, surface network and process simulation together for planning and managing MWAG injection to optimize recovery from an existing development.
- North America > United States > Texas (0.92)
- North America > United States > Alaska > North Slope Borough (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.36)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field (0.99)
- Asia > Middle East > Israel > Tel Aviv District > Southern Levant Basin > National Field (0.97)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Alpine Field > Kingak Formation (0.94)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- (2 more...)
Abstract A significant portion of the world's hydrocarbon reserves is found in heavy oil reservoirs. Heavy oils are often found in shallow and highly unconsolidated reservoirs, or sometimes in deep, tight formations. Often the high asphaltic content of these oils results in relatively higher oil density and viscosity; hence, their lower reservoir mobility poses significant challenges to both sampling and PVT data measurements. Furthermore, modeling these fluids for reservoir evaluation requires special techniques to capture their unique phase behavior. The challenges of representative down-hole or surface fluid sample acquisition demand customized sampling methods to deal with: low oil mobility sand production from unconsolidated formations high asphaltene content and resulting high gradients formation of water-in-oil emulsion during co-production of water or gas lift operations or addition of diluents In addition, the prerequisite for laboratory measurement is special sample preparation to remove emulsified water. These high viscosity oils exhibit slower gas liberation below the bubble point and hence delayed gas-phase formation, thus making "true" oil property measurements a challenge. Difficulties associated with fluid modeling include characterizing apparent bubble point behavior, large viscosity changes with pressure and temperature, and asphaltene dropout. In this paper, we present a comprehensive methodology for heavy oil sampling and characterization in unconsolidated sands as well as in low permeability reservoirs. We present field examples to highlight the challenges and illustrate the methodology for fluid sampling, down-hole fluid analysis, laboratory PVT data acquisition, and modeling. Sampling methods for heavy and asphaltic oils were custom designed with special tools and sensors to obtain representative samples and precise down-hole fluid analysis data. New laboratory techniques were developed to prepare the samples for analysis and to distinguish between the "true" and "apparent" bubble point behavior exhibited by the heavy oil due to its non-equilibrium behavior. Fluid models based on a special equations of state (EoS) were employed for accurate description of heavy oil fluid phase behavior. In particular, we successfully applied the industry's first EoS for asphaltene gradients in heavy oil reservoirs that match down-hole fluid data.
- South America (1.00)
- North America > United States (1.00)
- Asia (0.93)
- Europe (0.68)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Hamaca Area > Hamaca Area Field (0.99)
- Europe > Albania > Block 2 > Patos-Marinza Block > Patos Marinza Heavy Field > Marinza (0.98)
- Europe > Albania > Block 2 > Patos-Marinza Block > Patos Marinza Heavy Field > Gorani (0.98)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Capillary pressure can have a significant effect on multiphase flow in heterogeneous and fractured media, even when there is species transfer between the phases. Modeling the combined non-linearities from phase behavior and capillarity in the multiphase flow equations for heterogeneous and fractured media may be one of the most complicated problems in reservoir simulation. In this work, we present an efficient numerical scheme that uses higher-order methods for the first time to model capillarity in fully compositional three-phase flow. We introduce a simple local computation of the capillarity pressure gradients in the fractional flow formulation in terms of the total flux. Complications arising from gravity and capillarity are resolved in the upwinding with respect to phase fluxes. Our choice of the Mixed Hybrid Finite Element Method for the pressure and flux fields is an accurate and natural approach to compute the capillary pressure gradients and fluxes at the interface between regions of different permeabilities. We present various examples on both core- and large-scales to demonstrate powerful features of our capillary pressure modeling and the upwinding with gravity and capillary pressure. The examples include layered and fractured domains.
Abstract A new solution for determining the amount of mud loss during drilling operation in a fractured reservoir having a regular two- or three-dimensional radial fractured network with the novel inclusion of a convective transport of filtrate in the matrix is presented. Convective-dispersive filtrate transport along the network is modeled in which drilling mud can be filtered in existing matrix. The filter cake effect at the fracture-matrix interface in the network is simulated by means of an empirically decaying filter rate equation. The numerical solution is used in this study. The consistency of numerical solution is checked and the best situation is considered. The sensitivity analysis on all parameters in the model has been done and the effect of each parameters such as wellbore loss rate, reservoir thickness, fracture opening size, matrix porosity, matrix permeability and dispersivity, on the amount of filtration are inversitaged. By means of developed model, the amount of mud filtration can be plotted against position in different fractured network configurations for different wellbore conditions, reservoir properties and reservoir geometries at different times. The position in the fracture network at which the curve of concentration reaches zero can be considered to represent skin radius caused by drilling operation. This radius can be used for determining the acid volume which is needed for acidizing operation and accurate well-log interpretation.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Operations (1.00)
- (8 more...)
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 ‘gravity term’ 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 Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
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...)