Hani Elshahawi

Coarse and Ultra-Fine Scale Compartmentalization by Downhole Fluid Analysis

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Insitu Characterization of Formation Fluid Samples - Case Studies

Fluid sampling in the early stages of exploration and development provides key information for field planning and facilities design. In many deepwater and other high-cost wells, formation-tester samples may be the only reliable source of fluid properties for economic screening. Real-time in-situ fluid characterization can ensure sample quality and optimize the sampling process. Techniques for downhole fluid characterization include real-time composition measurement, fluid-type identification, and single-phase assurance.

Integration of Geochemical, Mud Gas and Downhole Fluid Analyses for the Assessment of Compositional Grading - Case Studies

Identifying compartmentalization, quantifying connectivity, and assessing the presence of compositional grading are critically important to reservoir management, particularly in deepwater projects where uncertainties are large and mistakes are costly. Compositional grading has been known for over 50 years, but the topic received little attention until the 1980’s when sufficiently advanced analytical methods became available to assess the phenomenon. Individually, geochemistry, downhole fluid, and mud gas analyses have provided valuable insights into compositional grading, but each analytical method relies on different fluid traits and has different implications. When these analytic methods are systematically combined and consistently applied, the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein. In this paper, we review two case studies in which we have combined multiple techniques for the assessment of compositional grading in different settings. We demonstrate that new technologies combined with real-time monitoring and control and a more integrated evaluation approach produce a more robust interpretation of the fluids and yield insights into reservoir architecture.

Improved Interpretation of Reservoir Architecture and Fluid Contacts through the Integration of Downhole Fluid Analysis with Geochemical and Mud Gas Analyses

Determining connectivity at the reservoir scale remains the elusive goal for predicting long-term production profiles. Characterization of reservoir architecture and the fluids therein is the biggest challenge in achieving this goal. Downhole fluid analysis along with complementary techniques including geochemical, mud-gas and pressure analyses provide valuable information about reservoir architecture. These analytic methods rely on different fluid traits. With systematical integration of these methods, the synergy delivers a much more accurate and robust picture of the reservoir. In this paper, we link traditional and novel methods for fluid analysis to build a more complete interpretation of fluid variations to provide greater insight into reservoir architecture. In particular, we show examples in which we integrate pressure gradient, PVT, mud-gas, geochemical and downhole fluid analyses in the identification of flow barriers, evaluation of connectivity across faults, and prediction of fluid contacts. The examples demonstrate how the integration of these methods with geological and geophysical models leads to an improved interpretation of reservoir architecture and fluid contacts.

Impact of Asphaltene Nanoscience on Understanding Oilfield Reservoirs

Understanding asphaltene gradients and dynamics of fluids in reservoirs had been greatly hindered by the lack of knowledge of asphaltene nanoscience. Gravitational segregation effects on oil composition, so important in reservoir fluids, are unresolvable without knowledge of (asphaltene) particle size in crude oils. Recently, the “modified Yen model” also known as the Yen-Mullins model, has been proposed describing the dominant forms of asphaltenes in crude oils: molecules, nanoaggregates and clusters. This asphaltene nanoscience approach enables development of the first predictive equation of state for asphaltene compositional gradients in reservoirs, the Flory-Huggins-Zuo (FHZ) EoS. This new asphaltene EoS is readily exploited with “downhole fluid analysis” (DFA) on wireline formation testers thereby elucidating important fluid and reservoir complexities. Field studies confirm the applicability of this scientific formalism and DFA technology for evaluating reservoir compartmentalization and especially connectivity issues providing orders of magnitude improvement over tradional static pressure surveys. Moreover, the mechanism of tar mat formation, a long standing puzzle, is largely resolved by our new asphaltene nanoscience model as shown in field studies. In addition, oil columns possessing large disequilibrium gradients of asphaltenes are shown to be amenable to the new FHZ EoS in a straightforward manner. We also examine recent developments in asphaltene science. For example, important interfacial properties of asphaltenes have been resolved recently providing a simple framework to address surface science. At long last, the solid asphaltenes (as with hydrocarbon gases and liquids) are treated with a proper chemical construct and theoretical formalism. New asphaltene science coupled with new DFA technology will yield increasingly powerful benefits in the future.

Variation of Asphaltene Onset Pressure Due to Reservoir Fluid Disequilibrium

Reservoir fluids in a single compartment can be in a state of gross thermodynamic disequilibrium. The equilibration of reservoir fluids is a slow process in part mediated via diffusion, an inherently very slow process. When reservoir fluids are subjected to other, faster processes, equilibration can be precluded. A common event in reservoirs especially in deepwater is a late gas charge into an oil-filled reservoir. In this case, the gas can quickly migrate to the top of the reservoir through fault planes without mixing with the existing reservoir fluid. This newly charge gas can then diffuse down into the oil column thereby creating very large gradients of many fluid properties such as gas-oil ratio (GOR) and bubble point pressures. In addition, asphaltene solubility is highly sensitive to GOR (as shown in the Flory-Huggins-Zuo Equation of State (FHZ EoS)), thus very large gradients of asphaltene content can likewise be established. Where solution gas is high, asphaltene instability is expected and Flow Assurance problems can occur. Gravity segregation of asphaltenes due to redistribution of the colloidal speciation of the asphaltenes in accordance with the Yen-Mullins Model can occur and results in asphaltene gravity currents. This process can result in significant variations in asphaltene concentration throughout the column. This convective process can yield large asphaltene concentrations at the base of the column thereby producing corresponding Flow Assurance concerns at the base. The combination of all these processes associated with gas charge into black oil can create a large gradient in asphaltene onset pressure (AOP). Such cases if not properly analyzed can give rise to mismanagement of Flow Assurance concerns. In this paper, we discuss case studies that exhibit such potentially problematic fluid columns. Simulated cases are also modeled to provide guidance for optimal management of AOP variations. The relationships of these Flow Assurance problems with other production problems are clarified. The ability to model asphaltene gradients with the FHZ EoS is seen to help significantly in understanding of asphaltene phase behavior of reservoir fluids.

Integration of Downhole Fluid Analysis and the Flory-Huggins-Zuo EOS for Asphaltene Gradients and Advanced Formation Evaluation

Abstract The Yen-Mullins model of asphaltenes has enabled the development of the industry’s first asphaltene equation of state (EOS) for predicting asphaltene concentration gradients in oil reservoirs, the Flory-Huggins-Zuo (FHZ) EOS. The FHZ EOS is built on the existing the Flory-Huggins regular solution model, which has been widely used in modeling the phase behavior of asphaltene precipitation in the oil and gas industry. For crude oil in reservoirs 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 is simply based on asphaltene clusters. The FHZ EOS has been applied to different crude oil columns from volatile oil to black oil to mobile heavy oil all over the world to address key reservoir issues such as reservoir connectivity/compartmentalization, tar mat formation, nonequilibrium with a late gas charge, and asphaltene destabilization by integrating downhole fluid analysis (DFA) measurements and the Yen-Mullins model of asphaltenes. 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, or/and asphaltene clusters. Field case studies proved the value and simplicity of this asphaltene or heavy-end treatment. Heuristics can be developed from results corresponding to the estimation of asphaltene gradients. Perylene-like resins with the size of ~1 nm are dispersed as molecules in high-GOR light oils (condensates) with high fluorescence intensity and without asphaltenes (0 wt% asphaltene). Heavy asphaltene-like resins with the size of ~1.5 nm are molecularly dissolved in volatile oil at 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). All these studies are in accord with the observations in the Yen-Mullins model within the FHZ EOS analysis. Furthermore, the cubic EOS and FHZ EOS have been extended to a near critical fluid column with GOR changing from 2600 to 5600 scf/STB and API gravity changes from 34 to 41 °API. Data from the real-time third-generation of DFA were used to establish the early time EOS for advanced formation evaluation. The early-time EOS was updated after the laboratory PVT data were available. The results from the early-time EOS based on the new-generation DFA data were in accord with those from the updated one based on the pressure/volume/temperature (PVT) data. The large GOR gradient is well modeled by the cubic EOS assuming a small late gas charge from the crest to the base. The FHZ EOS with 1-nm diameter was employed to predict the fluorescence intensity gradient. This agrees that perylene-like resins with the size of ~1 nm are dispersed as molecules in high-GOR light oil (rich gas condensate) with high fluorescence intensity and without asphaltenes (0 wt% asphaltene).

DFA Asphaltene Gradients for Assessing Connectivity in Reservoirs under Active Gas Charging

Identification of reservoir compartmentalization, q uantification of flow connectivity, and assessment of compositional gradients are critical for optimal reservoir charac terization, production, and management, especially in deepwater developments. Downhole fluid analysis (DFA) provides a useful tool to measure composition, gas/oil rat io (GOR), density, and color (linearly associated with asphaltene cont ent). In particular, DFA is the method of choice to measure gradients of reservoir fluids vertically and laterally. Based on DFA measurements and advanced asphaltene science, a new modified Flory-Huggins regular solution model that has been referred to as the Flory-Huggins-Zuo EOS has successfully been developed and used to delineate reservoir connectiv ity recently. It provides the industry’s first pred ictive asphaltene grading equation of state (EOS) and has proven reliable to predict connectivity in equilibrated oil columns. T he theory shows that asphaltene gradients can be large owing to both the gravity term and GOR gradients. In this case study, we demonstrate that the methodo logy for equilibrated reservoirs can be extended to nonequilibrium oil columns. We employ the new asphaltene Flory-Huggins-Zuo (FHZ) EOS for a reservoir currently undergoing active charging of biogenic gas. Isotope analysis shows that the bi ogenic methane is not equilibrated in this column. Nevertheless, the local asphaltene concentration within the column is shown to be equilibrated with the local GOR value and gr adient. Based on the properties computed by the Peng-Robinson EOS with methane influx, the FHZ EOS for asphaltenes - origin ally formulated for equilibrium columns - may also be used to model the asphaltene (color) gradient in this nonequilib rium oil column. The obtained 2-nm asphaltene diameter is also consisten t with field and laboratory data and is part of the Yen-Mullins model of asphaltene science (size of asphaltene nanoaggregat es). This methodology establishes a powerful new ap proach for conducting DFA color grading analysis by coupling t he Yen-Mullins model, and the FHZ EOS with DFA to address reservoir connectivity in reservoirs under active g as charging.

Low Level Hydrogen Sulphide Detection using Wireline Formation Testers

Many development projects will rely on producing through existing production facilities, which may not have been designed for sour hydrogen sulphide (H2S) service. This problem is compounded if production is routed to an NGL or GTL facility because even a tiny amount of H2S may dictate a prohibitively expensive upgrade.

Combining Conventional and Wireline Formation Testing for Improved Reservoir Characterization

Well testing has long been a valuable tool for the petroleum industry. The practice continues to be widely used today, but an increasing number of situations arise in which conventional well tests can be impractical due to cost, logistical or environmental constraints. For instance, in Arctic areas, weather conditions may dictate a time window beyond which operations must cease. In such cases, a wireline formation tester (WFT) test may present a viable alternative to acquire formation fluid samples and pressure transient data (WFT-PTA).