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A common challenge in exploration in the North Slope of Alaska is the formation evaluation of low-permeability formations when near-wellbore damage is caused by water-based muds (WBM). This study describes the novel application of existing technology to collect high-quality hydrocarbon samples efficiently in these challenging conditions. The concept was tested with a wireline formation tester in a well with severe formation damage caused by WBM. The procedure and hardware used are discussed and an example of the effectiveness of the proposed technique is shown. Due to the unfavorable mobility ratio, WBM filtrates tends to move preferentially while attempting oil sampling in low permeability rock leading to long station times during wireline formation testing operations. To overcome this challenge, a target sampling interval was subjected to high drawdown using a 3D radial probe to move the target phase closer to the wellbore. Once hydrocarbon was detected in the fluid analyzer, the 3D radial probe was retracted, and the string repositioned to cover the same interval with a straddle packer assembly. Straddle packers provide wellbore annular space for filtrate and hydrocarbon to segregate after the flow period is resumed. When hydrocarbons are again seen in the fluid analyzer, a simultaneous two-pump flow is used to collect them and discard the filtrate. The combination of 3D radial probe and straddle packer assists with displacing the mud filtrate, bringing the target hydrocarbons to the wellbore, and enables the collection of segregated samples with exceptional quality. After pumping at one sampling station using the 3D Radial probe, the maximum hydrocarbon fraction observed was 5%. When the straddle packer was positioned at the same interval, the fluid analyzer showed that the low velocity in the annular space between tool's mandrel and wellbore enabled hydrocarbon segregation from the filtrate due to the existing density contrast. When the hydrocarbon in the wellbore reached the straddle packer inlet, the lower pump was used to flow most of the filtrate in the down direction at high rate. Meanwhile, the hydrocarbon was "skimmed off" and placed in sample containers at a much lower rate using the upper pump. Laboratory results confirmed that the samples collected with the traditional sampling method contained 95% filtrate whereas the samples collected with our technique contained 90% hydrocarbon. Downhole fluid segregation using single-inlet, wireline straddle packer and dual-pump action has not been found in the literature. Recent developments in wireline formation testing use dual inlets in straddle packer modules to enable downhole segregation. We consider that the technique described here innovatively uses the capabilities of current formation testers to collect high-quality hydrocarbon samples in low permeability conditions. With minor adjustments, this technique can also be applied in gas or water sampling in wells drilled with oil-based muds.

The radius of investigation (ROI) of pressure transient analyses has been traditionally assessed using analytical formulations with basic reservoir parameters for homogenous systems. Numerous studies aimed to improve ROI formulations to incorporate all reservoir and testing parameters such as gauge resolution and rate for more accurate ROI assessments. However, new generation wireline formation testers aim to improve deep transient tests with significant developments in gauge resolution and increasing rate. Challenges still remain in heterogeneous formations such as shaly sands and carbonate reservoirs. In this study, detailed conceptual high-resolution numerical models are set up, including comprehensive reservoir and measurement parameters, to investigate more realistic ROI assessments in layered heterogeneous systems without and with hydraulic communication. Several conceptual examples are presented in layered systems with permeability contrasts. In addition, deviation from infinite-acting radial flow (IAFR) and pressure propagation in highly heterogeneous layered systems are investigated to detect the presence of geological features, including closed boundary systems and the presence of a fault in the proximity of wellbore.

SummaryA technique to quickly determine the asphaltene onset pressure (AOP) of a crude oil from low-volume, nonequilibrium measurements is presented. The pressure at which the optical signature indicative of asphaltene aggregation is first detected in recombined crude oils is found to decrease strongly with the rate of depressurization and can be well-described with a modified power law. This technique exploits this rate dependence and uses two separate decompressions at highly disparate depressurization rates to determine the AOP. Benchmarking with this technique was performed with recombined crude oils that were characterized with conventional pressure/volume/temperature analysis. Using this technique, measurements enabling the determination of the AOP of a live crude oil can be obtained in minutes with a nominal uncertainty of 500 psi. This is a significant reduction in time compared with the multihour process used for conventional equilibrium-based measurements. Onset-time data from these studies are consistent with conventional aggregation theories, but there is insufficient range to differentiate between reaction-limited aggregation (RLA) and diffusion-limited aggregation (DLA).

Offshore exploration requires the evaluation of hydrocarbon presence, estimation of volumes in place, and flow potential. To this capacity, formation testers are widely used to determine static data such as reservoir fluid gradients and reservoir pressure, obtain fluid samples, and to assess reservoir connectivity. Dynamic data, acquired with interval pressure transient testing and well testing techniques, are used to assess reserves and productivity. However, these evaluation techniques provide dynamic data at different resolution and length scales, and with different environmental footprint, cost, and operational constraints. A new wireline formation testing technique known as deep transient testing (DTT) has been introduced, which combines high-resolution measurements, higher flow rates, and longer test durations to perform transient tests in higher permeability, thicker formation, and at greater depth of investigation than with previous formation testers—without flaring and at a low carbon footprint. The platform combines advanced metrology with extensive automation to generate unique, real-time reservoir insights. Traditionally, pressure transient analysis and well deliverability predictions were produced through an analytical framework. Today, deep transient testing measurements are interpreted, and placed in reservoir context, in real-time by integration with geological and reservoir models. These steps can be performed from any wellsite utilizing cloud-based resources. Products such as reservoir fluid compressibility, saturation pressure, equation of state (EOS) models, well productivity, or minimum connected volumes are integrated in real-time interpretation utilizing numerical analysis. The digital infrastructure enables key reservoir insights to be shared between all stakeholders in a transparent and collaborative environment for both operational control and rapid decision making. This paper presents a case study where the new DTT technique was combined with numerical analysis and real-time integrated workflows to characterize a multilayer reservoir in a recent discovery in deepwater Mexico. During the drawdown phase of the DTT operation, real-time downhole fluid analysis was used to determine the fluid composition, density, viscosity, compressibility, and saturation pressure. These fluid properties were then used to generate and tune an EOS model. Accurate drawdown flow rate measurements and the subsequent pressure transients were combined with the fluid model and geologic model to enable integrated pressure transient history matching. The resulting calibrated numerical model honors the fluid measurements and geologic model and was used to predict the permeability profile, zonal producibility, and the volume of influence of the test.

A very large monotonic variation of asphaltenes and viscosity has been measured by downhole fluid analysis (DFA) in crude oils in five-stacked sandstone reservoirs in the northern part of the Barmer Basin, northwest India, undergoing active biodegradation; each of the five-layered sand bodies shows overlaying fluid gradients with depth providing replicate validation of the measurements. Fluid data from four wells across the field shows that the gradients are uniform across the formation. The crude oil in the upper half of the oil column exhibits an equilibrium distribution of asphaltenes matching predictions of the Flory–Huggins–Zuo Equation of state (FHZ EoS) with the gravity term only using asphaltene nanoaggregates of the Yen–Mullins model. However, the bottom half of the reservoir reveals a large asphaltene gradient approximately three times larger than the equilibrium predictions from the FHZ EoS. This increase in asphaltenes creates a very large (8×) viscosity gradient and is a major production conc...

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.

In order to reduce reservoir uncertainties, downhole fluid analysis (DFA) and the acquisition of highest quality reservoir fluid samples are of utmost importance, especially in deepwater Gulf of Mexico fields. While focused sampling technique has achieved these objectives in the most efficient and cost-effective manner for a wide range of the reservoirs, there are certain conditions where focused probe or conventional probes don't perform the best. Some of these challenging reservoirs include low permeability or laminated reservoirs, highly unconsolidated formations and reservoirs with highly viscous oil. A newly designed 3D radial probe provides sampling and DFA solutions in such challenging reservoirs. Large inlet flow area of the 3D radial probe facilitates efficient pumping and sampling in low mobility or laminated reservoirs. Conventional probe faces challenge of loss seals in unconsolidated reservoir which is overcome by radial probe due to its large sealing surface area. A case study from deepwater Gulf of Mexico is discussed in which complex reservoirs are tested for DFA and sampling using a 3D radial probe. Formation density, spectral gamma ray and neutron logs determine formation porosity and presence of shale. Triaxial resistivity identifies laminated zones and a laminated sand analysis is performed to add about 35% hydrocarbon pore thickness when compared to conventional, non-laminated analysis. This data was coupled with the latest generation microresistivity imager which allows accurate identification of geologic features, from very thinly-laminated bedding to faults and fractures. Fluid sampling and downhole fluid analysis are performed with wireline formation tester tool configured with conventional probes as well as 3D radial probe. Several pumping stations are performed, and 3D Radial probe enables sampling in thin low mobility rocks providing low contamination samples confirmed with the laboratory analysis. Insitu fluid analysis data was used for sample optimization, detailed downhole fluid characterization and reservoir connectivity assessment. The 3D radial probe also allows high quality pressure transient data for better permeability estimation. In addition, a vertical interference test (VIT) is performed with sink and observation probe configurations for vertical permeability and connectivity assessment. Additional inelastic and capture spectroscopy measurements were taken about two weeks after the well was cased, which validated critical petrophysical measurements. The spectral data was also used to further characterize the formation mineralogy.

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.

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.

Abstract Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall. We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe. This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool. Introduction A logical start for any wireline formation testing (WFT) operation is a tool string design that considers the formation evaluation objectives and expected formation and fluid properties. With the current availability of an arsenal of probes having different shapes, focused probes of circular or elongated design, and dual packers, this planning stage has now become a more complex process. The recently introduced 3D radial probe (Al Otaibi et al. 2012; Flores de Dios et al. 2012) adds another choice for the engineers in planning WFT surveys.

Abstract In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)-liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.

Understanding reservoir complexities such as compartmentalization and compositional gradients early on is crucial for optimal field development, especially in deepwater environments. Downhole fluid analysis (DFA) measures composition, gas/oil ratio (GOR), density, optical density (linearly associated with asphaltene content), and fluorescence intensity. Based on the Yen- Mullins model of asphaltene science and DFA measurements, the industry's first predictive asphaltene equation of state (EOS), the Flory-Huggins-Zuo (FHZ) EOS has been developed. It has been successfully used to estimate asphaltene concentration (optical density, OD) gradients and help predict reservoir connectivity – subsequently proven by production data. This provides an advanced reservoir evaluation tool, which reduces uncertainty in reservoir characterization. In this paper, DFA and the FHZ EOS were used to analyze a couple of case studies: The first deals with a black oil column with a steep asphaltene gradient; the second and third deal with a light (near critical) oil with a large compositional gradient. For the black oil column, detailed analysis of recently available pressure data suggests that this oil column is disconnected from the aquifer and from the regional pressure regime. For the light oil columns, the delumping technique (Zuo et al., 2008) was used to obtain compositions from the DFA data which compared well with gas chromatography data. The cubic EOS was applied to describe the large variations observed in composition, GOR and density. The obtained results were also in good agreement with the measurements. Because of very low optical absorption in this light oil column, the FHZ EOS was employed to analyze the fluorescence intensity gradient, which is correlated with a fraction of heavy resins. The FHZ EOS has been successfully extended to light oil with very low optical absorption but a large fluorescence intensity gradient for the first time. The results show that the heavy resin is molecularly dispersed in this light oil column, and the GOR gradient creates the fluorescence intensity (heavy resin) gradient via the solubility term of the FHZ EOS. The equilibrium heavy resin distribution suggests this oil column is connected, which is also proven by other log and production data with the latter indicating a variable mix of the end members. In addition, tar mat formation is reviewed showing that the physical chemistry approaching embodied by the FHZ EOS and the Yen-Mullins model can treat asphaltic fluids as well. In particular two fundamental methods of tar mat are identified; one mechanism is from gas addition, where solution gas increases causing tar mat formation with a discontinuous increase of asphaltene content at the oil-tar contact. The other mechanism is by asphaltene addition, where the concentration of asphaltene is increased beyond its solubility limit. This type of tar yields a continuous increase in asphaltene concentration at the oil-tar contact. Note that in contrast to other putative explanations, water plays no role in either of these mechanisms for tar mat formation.

Many sedimentary features of hydrocarbons at Western Desert are characterized as multilayered, deltaic, thinly and tight laminated sandstones consisting of sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations among nearby wells proved to be inconclusive in identifying hydrocarbons reservoirs owing to their thin beds, high shale content, and variable formation water resistivity. Missing hydrocarbon-bearing formations translates into lost productivity, while perforating water zones can have detrimental effects on well performance. Given these complexities, fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. The main challenges faced during wireline formation testing in the reservoirs studied have been a) laminated, low mobility and thin formations with varying water salinity, b) no representative fluid samples due to deep mud filtrate invasion, c) eventual formation damage while drilling The pretest/sampling efficiency with wireline formation testers and by using single probes has been traditionally very low in thinly laminated reservoirs because of the high possibility of dry or tight tests with long pressure stabilization time and not sampling or high contaminated samples. To displace invade fluids in low permeability formations can be challenging, usually requiring a high drawdown to pump the move filtrate from formation. To improve the job efficiency, High Performance packers and pumps are essentially in such environment that reduce significantly the differential pressure while pumping and increase the envelop to test zones beyond capabilities with the single probes. The Interval Pressure Transient Tests (IPTT) technique has been recently launched to increase the success ratio of wireline formation testers in getting reliable pressures and fluid analysis, including real-time monitoring of each survey by reservoir engineers.