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Representative fluid properties are required for a wide range of field life aspects such as initial sizing of reservoir hydrocarbon reserves and production planning. Fluid properties are routinely obtained from laboratory sample analysis, but some fluid properties can also be measured in situ with formation testers. A new downhole bubblepoint technique has been developed to supplement traditional downhole fluid analysis measurements. Bubble-initiation pressure is measured on reservoir fluids enabling early estimations and sample representativity. The method outlined consists of two parts: bubble generation and bubblepoint-pressure detection. After isolation of a volume of contamination-free fluid in the fluid analyzer module of a formation tester, a downhole pump is used to reduce flowline pressure at a low and precise flow rate. Bubble initiation is detected using optical spectroscopy measurements made at a 64-ms data sampling rate. Even very small bubbles scatter visible and near-infrared light directed through the flowline, ensuring that the initiation of bubbles is detected. Flowline decompression experiments are performed in minutes, at any time, and on a wide range of downhole fluids. Downhole bubblepoint pressure measurements were made on four different fluids, all from different reservoirs and regions. The gas-oil ratio of the tested fluids ranged from 500 to 1,500 scf/bbl. In each case, the downhole bubblepoint obtained from the flowline decompression experiment matched the saturation determined by constant composition expansion in the laboratory to within 50 psi. We observed that bubble initiation is first detected using near-infrared spectroscopy. As pressure drops, gas bubbles coming out of solution will increase in size, and the bubble presence becomes identifiable on other downhole sensors such as the live fluid density and fluorescence, where it manifests as signal scattering. For each of the investigated fluids, pressure and density measurements acquired while the flowline pressure is above saturation pressure are also used to compute compressibility as a function of pressure. This downhole bubblepoint pressure measurement allows optimizing real-time sampling operations, enables fluid grading and compartmentalization studies, and can be used for an early elaboration of a fluid equation of state model. The technique is well-suited for black oils and volatile oils. For heavy oil with very low gas content, the accuracy of this technique may be reduced due to the energy required to overcome the nucleation barrier. Prior documented techniques often inferred downhole bubblepoints from analysis of the rate of change of flowline pressure. Direct precise detection of the onset of gas bubble appearance without the need to divert fluid flow is shown for the first time on a wide range of fluids. The measurement accuracy is enabled by the combination of 64-ms optical spectroscopy with low and accurate decompression rates.

A new definition of the radius of investigation (ROI) is proposed to overcome the ambiguity present in the results from conventional ROI quantification methods. The term ROI is commonly used to quantify the minimum reservoir size or the distance to a potential boundary evaluated through pressure transient testing. However, the various methods that exist in the literature to quantify ROI provide different answers stemming from varying assumptions and thus often lead to confusion in terms of the appropriate definition to choose. Although the ROI method developed by Van Poolen is well recognized in the industry, there is a debate about its general applicability because it is limited to a constant-rate flow period and is insensitive to flowrate and flow sequence, to gauge resolution or measurement noise level. This contrasts with operational experience, where a higher flowrate, higher gauge precision, and a lower level of measurement noise generates higher quality pressure transient testing data from which reservoir boundaries, or other features, can be identified farther away from the wellbore. In other words, higher flowrates, better gauges, and lower noise levels can lead to larger achievable ROI. We propose a new definition of ROI, that is the detectable ROI for each drawdown or build-up flow period and is derived from the actual pressure derivative response and not from a generic model assumption. By defining a derivative noise envelope, the new method clearly identifies the time when the derivative deviates from an unbounded model due to the presence of a boundary and thus provides an estimate of the detectable ROI for the analyzed period. This method overcomes the limitations of most conventional methods and provides ROI predictions that depend on flowrate and gauge noise while maintaining a consistent result with current pressure transient interpretation.

Fluid distributions throughout oilfield reservoirs have been measured with increasing accuracy and coverage, both vertical and laterally, in recent years. Currently, a routine observation is that, ...

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.

Openhole oil sampling in the tight Middle Cretaceous reservoirs of Alaska can be challenging due to the proximity of the reservoir pressure to the fluid’s saturation pressure. Existing focused probe technologies commonly used in other conditions have limited application in these conditions because their small flow area means slow pumping rates, high drawdowns, and nonrepresentative fluid samples. Nonfocused inlets, such as 3D radial probes and straddle packers, are mostly used to sample in these reservoirs, but deep invasion and slow pumping rates mean using these alternatives leads to long station times. A new wireline formation testing platform has been field tested in three wells since 2018. The objectives included the evaluation of the platform’s abilities to pump at controlled speeds to keep flowing pressures always above the fluid’s expected saturation pressures. A new inlet was tested for focused sampling and higher flow rates with the intention of cutting operating time and improving sample quality. Also, increased sample container capacity enabled the collection of required sample volumes in fewer bottles, which resulted in a shorter and lighter sampling string configuration. A legacy pressure tool was added to the bottom of the new platform for pressure testing benchmarking. During the operation, the tool was positioned at target depth, and an automated routine inflated the inlet assembly to contact the formation. This automation cycle enables the tool to be ready for pumping in less than 15 minutes. In contrast, technologies used in previous operations required 30 to 45 minutes setup time before fluid cleanup could commence. Fluids were then flowed through the tool’s sample and guard lines with a sequence of commingling and focused pumping periods using two simultaneous pumps while assessing fluid quality with a downhole fluid analyzer. Strict control of the 1-cm3/s selected rate for both pumps provided fast cleanup in focused mode with less than 100-psi drawdown. This has never been achieved before in these reservoirs. First hydrocarbon breakthrough was observed less than an hour into the pumping period. Previous operations reported 4 hours or more for first hydrocarbon breakthrough. Three stations were performed, and 10 single-phase samples were collected in as many bottles. Thin-bedded interval testing was possible given the ability of the new platform to collect samples with either the sample or guard lines. Total operating time to complete the program was 30 hours. Comparison with data from similar operations in previous campaigns shows a decrease of 50% in operating time, faster rig- up and rig-down, and decreased cable tension. These latter two aspects add to operational efficiency and mitigation of risks. This case study summarizes several pioneering aspects of the new generation of wireline formation testing platforms. It was the first time a combination of the new and legacy technology was deployed and the first time that high-volume multiphase sample bottles were used during a field test. It was also one of the first applications of this new technology in North America.

A downhole fluid analysis prototype module (MRPV) has been developed which measures both asphaltene onset pressure (AOP) and bubblepoint pressure (Pb). This manuscript describes one of many recent downhole jobs which were part of a study to characterize live crude oil in real time while sampling mobile oil in a permeable tar mat. These jobs support an enhanced oil recovery (EOR) study to understand the best way to extract bypassed oil (Fatma 2019). In this manuscript, downhole bubblepoint and AOP measurements made with the MRPV in well RA-0Y37 agree with those obtained in a laboratory with bottomhole samples. The effect of oil-based mud contamination on the AOP and Pb is examined during clean up while sampling. Water was present for all jobs, but the hydrophobic membrane blocked water from entering the MRPV, facilitating ease of interpretation of optical data. This manuscript comprises the first part of a two-part series (Tiwari 2020).

A new method to determine the dewpoint pressure of a retrograde condensate from a fast, non-equilibrium measurement performed in a microfluidic optical cell is presented. The inflection point of the optical transmission recorded during depressurization agrees well with the dewpoint pressure of the sample, determined by conventional laboratory techniques. With this new technique, a measurement can be performed in less than 5 min and requires far less than a milliliter of the sample. Benchmarking of this technique is presented using four retrograde condensate samples, which were created in the laboratory using multi-component compositions that are based on oilfield samples. Each sample was characterized at three different temperatures, and their maximum relative liquid volumes (maximum liquid volume/total system volume at the dewpoint pressure) ranged from 1.3% to 13.5% for these temperatures. The dewpoint pressure measured by this technique differs by no more than 100 psi from that measured in a conventional laboratory for samples of a richness of 4% or higher, while leaner samples display a difference of ∼200 psi.

Wireline formation testing has been routinely used for reservoir characterization in the Gulf of Mexico. The significant impact that fluid composition has on designing and operating production and processing facilities for these complex reservoirs requires comprehensive fluid sampling during exploration and appraisal. Vertical and lateral connectivity, fluid compatibility when commingling to meet production targets, or asphaltene onset potential along the production flow path are examples of the need for thorough understanding of fluid property variations. This case study combines the use of the newest generation of formation testing platform with innovative workflows to acquire critical fluid data and refine the geological reservoir model in near real time. Conveyance difficulties foreseen in the S-shaped well suggested that the use of a shorter, lighter tool could increase the chances of success in a field where past keyseating episodes left few reliable alternatives for conveyance apart from drillpipe-conveyed logging. The application of the smart sampling platform capabilities introduced important changes to the standard protocols used in these cases. The increased cleanup efficiency of the new formation testing technology enabled fast investigation of reservoir fluids at multiple depths with robust metrology for specific properties. The outstanding sample purity formed the foundation of advanced interpretation workflows. With its high-quality fluid data, this case was used to perform a "proof of concept" of advanced interpretation workflows aimed at updating geological and fluid models in near real time once the downhole fluid analysis data become available at the end of each sampling station. The formation testing data and the near real-time answers expedited tailoring the completion of the well, which involved a nontrivial commingle decision. The fluid information also provided clarity for the geological model in a section of the field where the current seismic interpretation had shown uncertainty for the reservoir architecture in the downthrown block of the field. The combination of new formation testing hardware and short-cycle workflows makes this case study the first of its kind. The proof of hardware performance and data processing/interpretation capability cements the case for higher-density data streams and a shortened data life cycle. It serves as a preview of how digitally enabled formation testing operations will be conducted in the future to provide new insights to reservoir understanding.

In recent years, the Flory-Huggins-Zuo Equation of State (FHZ EoS) has been utilized to treat asphaltene gradient data in many oilfield reservoirs. The FHZ EoS employs asphaltene species from the Yen-Mullins model consisting of molecules, nanoaggregates and clusters of nanoaggregates; the specific species used depends primarily on the concentration of asphaltenes but also on the asphaltene stability. Reservoirs with equilibrated asphaltenes are repeatedly found to produce oil as a single flow unit addressing a key reservoir property. For crude oils with moderate concentrations of asphaltenes (a few%), asphaltenes are typically dispersed as nanoaggregates. In crude oils with high concentrations of asphaltenes (∼10%), asphaltenes are typically dispersed as clusters of nanoaggregates. This paper examines a reservoir with a crude oil of moderate concentration of asphaltenes where a secondary charge of methane created some limited instability of asphaltenes. Many pressure and fluid measurements are made to determine that indeed the fluid column is equilibrated. The FHZ EoS and the Yen-Mullins model in this equilibrated oil column are then compared with the asphaltene gradient; excellent agreement is obtained extending the use of this thermodynamic modeling to crude oils with limited asphaltene instability. Downhole fluid analysis (DFA) is used to delineate the asphaltene gradient, and both DFA and lab data are used for determination of solution gas content of oil samples. Conventional gas chromatography, two-dimensional gas chromatography (GC × GC) and gas isotope analysis are performed to analyze the oils, all with a focus to test and ensure thermodynamic equilibrium of the oil column. The mixed charge of an oil and a secondary gas is confirmed identifying the source of asphaltene instability. The result of the asphaltene instability is to create a fraction of crude oil at the base of the oil column with asphaltenes dispersed as clusters of asphaltenes, thus exhibiting a larger asphaltene gradient there. Fluid inclusion measurements are useful to indicate the sequence of events in gas and oil charging into the reservoirs in geologic time. The Flory-Huggins-Zuo EoS and the Yen-Mullins model continue to be confirmed in oilfield studies as well as in the laboratory, even in cases of limited asphaltene instability observed here.

Reservoir fluid analysis can be used to better understand a hydrocarbon reservoir. Reservoir fluids are not always equilibrated in particular because of dynamic processes such as late gas charges occurring in the recent geologic past. It is of great importance to delineate how a late gas charge affects fluid distributions and when asphaltenes become unstable in oil. In this work, we modify the simplified moving boundary one-dimensional diffusive model of Zuo et al. (Energy 2016, 100, 199) for gas charges into oil reservoirs considering the Maxwell–Stefan diffusivity and thermodynamic nonideality. Live oil is simply treated as three pseudocomponents: gas, maltene, and asphaltene. The parameters of the three components in the Flory–Huggins regular solution model are calibrated by the Peng–Robinson equation of state. The modified diffusive model is then used to simulate gas charges into oil reservoirs. The simulation results have indicated that fluid density inversion is created by competing effects of aspha...

The accuracy of the phase envelope calculated for a black oil sample strongly depends upon the quality and type of information used to optimize the equation of state (EOS). Possible inputs for EOS tuning include (but is not limited to) composition from a chromatogram or optical absorbance, density, saturation pressure (bubble or dew point pressure), and the relative volumes of liquid and gas. In this manuscript, we describe a workflow using a system of microsensors that our group has previously published that accurately measures fluid properties from which the phase envelopes of several black oil samples are calculated and refined.

Acquisition of fluid samples using wireline formation testers (WFTs) is an integral part of reservoir evaluation and fluid characterization. The increasing complexity of fluid sampling operations, especially in remote or offshore fields, requires a careful planning process involving systematic de-risking of the sampling objectives through quantitative evaluation of sampling hardware performance under uncertain downhole conditions and reservoir properties. During job execution, the cleanup of mud filtrate is monitored using downhole fluid analysis (DFA) sensor measurements. In addition to quantifying produced contamination and providing guidance for real-time decisions, these measurements hold valuable information about formation and fluid properties that can be extracted through advanced interpretation workflows. In this paper, we demonstrate how a quantitative, model-based workflow was applied to both planning and interpretation for a series of sampling jobs in a remote and harsh environment. At its core, the workflow consists of high-resolution numerical flow models for the filtrate cleanup process that cover both conventional and focused sampling tools. To enable real-time, interactive, and probabilistic workflows, we use machine learning techniques to construct fast, high-fidelity proxy models, which, after thorough validation, replace numerical simulation in the workflow. Finally, the workflow employs methods for uncertainty quantification, global sensitivity analysis, and model inversion. During the pre-job planning phase, the model-based workflow was used to select and mobilize the optimal sampling hardware, estimate sampling time uncertainty, and pinpoint the dominant sources of this uncertainty through global sensitivity analysis. After successful sample acquisition, the DFA measurements were reconciled with the cleanup model and the petrophysical evaluation to extract additional value from the measurements. Using measurements of water-cut and pressure, and conditioned to the petrophysical evaluation, the cleanup model was inverted for two-phase relative permeabilities. This recently developed methodology complements laboratory measurements of relative permeability on core samples. Building on previous work in this area, this paper demonstrates the practical application of advanced planning and interpretation workflows for downhole fluid sampling. The methodology presented couples traditional, full-physics flow modeling with modern machine learning techniques to achieve highly agile workflows, enabling operators to more efficiently plan sampling jobs and extract value from the measurements.

Analysis of spatial gradients of the concentration of asphaltenes in reservoir crude oils has become an important tool for oilfield reservoir characterization. Modeling these gradients requires knowledge of asphaltene properties. For example, the commonly employed Flory–Huggins–Zuo (FHZ) equation requires the asphaltene particle size, solubility parameter, and density. Asphaltenes from various sources, particularly including sources beyond conventional crude oil, can have widely varying compositions such as the H/C ratio. Here, we measured the solubility parameters and densities of five asphaltenes that span a large range of H/C ratios, including asphaltenes from coal, petroleum, and shale, and then performed a sensitivity analysis to examine how that range of compositions impacts the magnitude of asphaltene gradients as predicted by the FHZ equation. Two case studies are included in the sensitivity analysis, one in which the asphaltene gradient is driven primarily by gravity, and another in which the asp...

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.

Accurate quantification of oil-based drilling mud (OBM) filtrate contamination of hydrocarbon samples is still one of the biggest challenges in formation fluid sampling with formation testers. There exist contamination quantification techniques, but they can be technique sensitive, lack a confident level of quality control and apply only to a limited combination of probe types and formation fluid types. In particular, current techniques rely on an assumed absence of mud filtrate coloration at relevant optical channels and on sufficient optical density contrast between mud filtrate and virgin fluids. Such assumed fluid properties may not materialize when, for example, drilling muds are reused in multiple wells or when virgin fluids exhibit little color due to the absence of asphaltenes. In this paper, new mixing rules have been developed for mass density and shrinkage factor and for the newly defined “ f -function” and “ q -function”. The f -function, also referred to as the modified gas/oil ratio, is essentially a combination of gas/oil ratio with shrinkage factor. Similarly, the q -function is referred to as modified composition and is a combination of composition with mass density. OBM filtrate contamination in volume fraction, optical density, f -function, mass density, shrinkage factor, and q -function at a specified downhole sampling station have been found to be mutually linearly related as predicted by the mixing rules. The mutually linear relations are further confirmed by laboratory data for different mixtures of mud filtrate and formation fluids. Application of these mixing rules enables accurate OBM filtrate contamination in hydrocarbon samples if the filtrate properties and virgin fluid properties can be determined. A new methodology has been developed to determine the properties of the virgin formation fluid and mud filtrate, which are referred to as endpoints. The mud filtrate properties are obtained by extrapolating the mutually linear relations established from the cleanup data to zero gas/oil ratio or other known filtrate values such as zero methane composition, and/or zero optical density at specified wavelengths. The virgin fluid properties are determined by the power-law fitting of cleanup data coupled with the flow regime identification which is confirmed by large number of downhole fluid analysis datasets from wireline formation testers and numerical simulation. This novel methodology enables accurate quantification of the OBM filtrate and pure virgin formation fluid. Furthermore, the self-consistency of using multiple independent sensors provides confidence and greatly improves the robustness and quality control of OBM filtrate contamination monitoring downhole. Finally, contamination results can be expressed in volume or weight percent and as live fluid or stock-tank liquid fraction for easy comparison to laboratory results. A latest generation downhole fluid analysis (DFA) tool was employed to measure fluid properties downhole in real time on more than 30 DFA stations acquired with either conventional probes or 3D radial probes. The new methodology was applied to each of the acquired datasets. All the results from the new method are in good agreement with the results of the laboratory analysis.

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.

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.

Deepwater 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.

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.

This paper describes how the combination of Downhole Fluid Analysis (DFA) optical density for measuring asphaltene gradients combined with Flory-Huggins-Zuo (FHZ) EoS thermodynamic analysis is the method of choice to identify (in real time) three major field economical risks: compartments, connectivity and baffling. A deepwater field example from exploration/appraisal phase to development phase is reviewed. In this particular case, and for the first time within one field, DFA oil color measurements reveal initial or preserved charges, equilibrated charges and an intermediate state (monotonic gradient of asphaltenes but in disequilibrium). When part of the field is equilibrated and another part not equilibrated, the implication is that baffling impedes equilibration and production; both expectations are confirmed herein. Production data confirms that the region of the reservoir with equilibrated asphaltenes had much better production rates than the region with asphaltenes in disequilibrium. Moreover, the baffles are found to be associated with deformation banding seen in core and borehole image log. In addition, the improved understanding on controls over production rates helps to project wellbore results away from wellbore. The paper describes the detailed workflow using DFA asphaltene measurements and the FHZ EoS to successfully address many key reservoir properties at early and all stages of reservoir exploration and production.

The measurement of geomechanical properties of reservoir rock and caprock for completion optimization, enhanced oil recovery (EOR), and disposal/storage of any kind is becoming an integral and key aspect of asset evaluation and appraisal. One of the most important of these characteristics is an in-situ evaluation of the magnitude and variation of the minimum in-situ stress, the measurement of which is critical for geomechanical modelling and thereby a range of applications such as well construction, caprock integrity, and completion optimization. A wireline formation testing (WFT) tool is a common approach for obtaining direct measurements of these stresses at a range of depths. This process is referred to as microfracturing and is most typically performed in an openhole environment. Typical toolstrings consist of a straddle packer arrangement, a pumping mechanism, gamma ray for accurate depth correlation, a motorized valve/manifold arrangement, and pressure/temperature gauges. To perform a stress test, a specific interval of the wellbore is isolated by inflating the straddle packers. The interval is then pressurized by incrementally pumping fluid until a tensile fracture has been initiated. In an open hole, the fracture will initiate and propagate normal to the minimum stress at the wellbore and multiple injection and falloff cycles are subsequently performed to ensure fracture growth beyond the influence of the hoop stress regime. The data are then analysed to determine fracture initiation, reopening, propagation and closure pressures. Additionally, it may be possible to approximate fracture orientation, if an image log is available. This paper describes the process of obtaining minimum in-situ stress measurements using a WFT and advanced integrated stress analysis (ISA) process, in an ultradeep reservoir at ultrahigh pressures. Lessons learned and best practices are highlighted along with their importance for efficient job execution. The integrated geomechanical analysis covers subsequent generation of a calibrated stress model with minimum horizontal stress measured during microfracturing. Factors include evaluation of the stress contrast in the target formations and evaluation of the overburden gradient and mechanics for microfracturing job design for future operations (breakdown pressure) and lessons learned such as station selection, backup packer availability, and influence of stress cage material on breakdown, to name but a few. Obtaining accurate knowledge of in-situ minimum stress values, based on actual measurements, is a key step on the road to effective execution, and the earlier that this is achieved, the more efficient the results of any development. This paper summarises the successful application of the WFT approach in delivering such data under extremely harsh depth and pressure conditions, but resulting in a measurement from which numerous subdisciplines can conduct their decision making and design.

Viscosity is one of the key reservoir fluid properties. It plays a central role in well productivity and displacement efficiency and has a significant impact on completion strategies. Accurately assessing areal and vertical variations of viscosity will lead to more realistic reservoir simulation and optimal field development planning. Downhole fluid analysis (DFA) has successfully been used to measure the properties of reservoir fluids downhole in real time. DFA has excellent accuracy in measuring fluid gradients which in turn enable accurate thermodynamic modeling. Integration of DFA measurements with the thermodynamic modeling has increasingly been employed for evaluating important reservoir properties such as connectivity, fluid compositional and property gradients. The thermodynamic model is the only one that has been shown to treat gradients of heavy ends in all types of crude oils and at equilibrium and disequilibrium conditions. In addition, fluid viscosity depends on concentration of heavy ends that are associated with optical density measured by DFA. Therefore, mapping viscosity and optical density (heavy end content) is a new important application of DFA technology for use as assessment of reservoir architectures and a mutual consistency check of DFA measurements. In this case study, a very large monotonic variation of heavy end content and viscosity is measured. Several different stacked sands exhibit the same profiles. The crude oil at the top of the column exhibits an equilibrium distribution of heavy ends, SARA and viscosity, while the oil at the base of the oil column exhibits a gradient that is far larger than expected for equilibrium. The fluid properties including SARA contents, viscosity and optical density vary sharply with depth towards the base of the column. The origin of this variation is shown to be due to biodegradation. GC-chromatographs of the crude oils towards the top of the column appear to be rather unaltered, while the crude oils at the base of the column are missing all n-alkanes. A new model is developed that accounts for these observations that assumes biodegradation at the oil-water contact (OWC) coupled with diffusion of alkanes to the OWC. Diffusion is a slow process in a geologic time sense accounting for the lack of impact of biodegradation at the top of the column. An overall understanding of charging timing into this reservoir and expected rates of biodegradation are consistent with this model. The overall objective or providing a 1st-principles viscosity map in these stacked sand reservoirs is achieved by this modeling. Linking DFA with thermodynamic modeling along with precepts from petroleum systems modeling provides a compelling understanding of the reservoir.

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.

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.

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.

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.

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.