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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.

Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.

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, ...

The process of compositional equilibration of reservoir crude oil requires excellent reservoir connectivity. For example, the measured of asphaltene gradients for indications of connectivity is now commonplace. In addition, equilibrated fluids imply various other important fluid and reservoir properties. However, some measurements of distinguishing equilibration from disequilibrium have been ambiguous. Here, we provide measurement protocols which provide robust determination of equilibrium within a framework of reservoir fluid geodynamics. Thermodynamic modeling of measured asphaltene gradients vertically and laterally with considerations of solution gas provides a robust determination of equilibrium. In addition, two-dimensional gas chromatography with its high-resolution compositional evaluation especially within a geochemical context can corroborate conclusions from asphaltene gradient analysis. Outlier locations in the reservoir can often be found and aid considerably in delineating the important reservoir fluid geodynamic processes operative in the reservoir and validating the assessments regarding equilibrium. The evolution of lateral equilibration is shown in a reservoir with known initial (at time of charge) and present-day lateral gradients. Modeling clarifies the convection which has occurred over geologic time to minimize these lateral gradients. Different processes of mass transport in reservoirs are compared. Equilibration processes and corresponding asphaltene gradient measurements are analyzed for differing geologic times including a very young (Pleistocene and Pliocene) and very old (Cretaceous) reservoir charges in different reservoirs. The important role of convection is shown, with its critical requirement of a density inversion.

In toluene, asphaltenes are dispersed as molecules at low concentrations, as nanoaggregates at moderate concentrations, and as clusters of nanoaggregates at high concentrations. These three asphaltene species are codified in the Yen–Mullins model. For reservoir crude oils, equilibrated asphaltene gradients can be modeled with the Flory–Huggins–Zuo equation of state (EoS). The gravity term and other terms depend on the particle sizes of the asphaltenes which are given in the Yen–Mullins model; these different asphaltene species (molecular and two nanocolloidal species) have been identified in gravity gradients in various reservoir studies. Here, the asphaltene gradient in a large reservoir is examined and found to be consistent with a molecular dispersion of asphaltenes in the crude oil. A variety of fluid and reservoir properties are evaluated to ensure validity of the analysis, particularly of thermodynamic equilibrium of the reservoir fluid. For crude oil samples throughout the reservoir, downhole fluid...

Hydrocarbon reservoir fluids often undergo dynamic processes such as multiple hydrocarbon charges and biodegradation over geological time. These processes change the spatial distribution of hydrocarbon components in reservoirs and include diffusion, advection and phase change over geologic time. To better understand reservoir fluid geodynamics (RFG), a set of generalized diffusion-advection equations are proposed at isothermal conditions. The Maxwell-Stefan diffusivity in the gravitational field is integrated into the diffusion equations. Thermodynamic models are used to describe nonideality of reservoir fluids and phase separation. The generalized diffusion-advection equations are then simplified for a 1-D diffusion problem. The 1-D diffusion model is applied to the Lundin oilfield case study in Norway. The reservoir fluids are simply grouped into three pseudocomponents: gas (including solution gas), asphaltene and maltene. The Peng-Robinson equation of state is employed to estimate the parameters in the Flory-Huggins regular solution model. A ternary phase diagram including binodal and spinodal phase boundaries is computed based on the thermodynamic model. Asphaltenes are further treated as two forms: nanoaggregates and clusters in the gravitational diffusion term. The new RFG model captures the main physics of the reservoir fluid geodynamic process in the field case. Because gas (light hydrocarbon) charging from the top of the oil column leads to an increase in oil solution gas and a decrease in oil solvency capability to dissolve asphaltenes, asphaltenes are expelled downwards and accumulate at the base of the oil column. In addition, because asphaltene clusters have much bigger sizes than nanoaggregates, they increase the rate of asphaltenes accumulation at the base of the oil column over geological time. The resulting single RFG model is used to account for two adjacent reservoirs with very different fluid distributions. In fault block 1, there are large, disequilibrium gradients of solution gas and asphaltenes with little asphaltene deposition. In this fault block, the rate of diffusion is reduced by known reservoir baffles. In contrast, in fault block 2, the diffusion and asphaltene migration processes essentially went to completion yielding equilibrated solution gas and asphaltene gradients. In addition, after migration to the base of the oil column, the asphaltenes underwent phase separation with increasing solution gas. The same RFG model is used for both fault blocks but with different rates of diffusion associated with the known difference in reservoir baffling. This RFG model accounts for all measured fluid gradients and asphaltene phase separation in two fault blocks with very different distributions. In addition, the primary difference in the two adjacent reservoirs is the extent of reservoir baffling; this parameter created a factor of ten difference in production rates from these fault blocks. This new fluid modeling accounting for the reservoir fluid geodynamic processes in reservoirs is shown to impact major production concerns.

Asphaltene gradient analysis in many wells in a large field match the Flory-Huggins-Zuo Equation of State (FHZ EoS) indicating equilibrated asphaltenes, thus reservoir connectivity. This analysis is consistent with data from over one year of production to date. Reservoir fluid samples were acquired with use of focused sampling techniques providing contamination free samples. Pressure measurements and many fluid properties are used to validate fluid equilibrium, including GOR and composition analyzed by the Cubic EoS, and a variety of markers in the condensate range, black oil range and the biomarker region. All analyses indicate equilibrium with the exception that the only two outliers in the asphaltene gradient curve are shown to be of different thermal maturity by utilizing the preferred biomarkers, the hopanes Ts and Tm. Moreover, the asphaltene abumdance in differently charged fluids varies by a factor of 6 while the maturity ratio Ts/(Ts+Tm) varies by 6% showing the sensitivity of asphaltene gradients for connectivity analysis. The modest levels of biodegradation (Peters- Moldovan rank=1) are used to constrain the petroleum system context of this reservoir considering that current reservoir temperatures significantly exceed biodegradation thresholds. There is evidence both that mildly biodegraded oil spilled into this reservoir and that some further biodegradation occurred in reservoir. Different gas-oil contacts in the field are associated with charge direction and show the limits of Cubic EoS for connectivity analysis in contrast to the good capability of the asphaltene gradients and FHZ EoS for this purpose. Moreover, the FHZ EoS analysis indicates that the asphaltenes are dispersed as a true molecular solution for this light oil in accord with the Yen-Mullins model of asphaltenes. Results from detailed whole-core and petrophysical analyses supports connectivity analysis. Core analysis shows the lack of any asphaltene deposition in the reservoir as expected from the fluid and asphaltene evaluations.

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.

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.

In this reservoir study, three adjacent structures have been subject to largely the same fluid charge with an original oil charge and a very recent light hydrocarbon charge (all indicated by petreolum systems modeling and organic geochemical analyses). In addition, all wells have an oil-water contact (OWC) and two have a gas-oil contact (GOC), while the GOC in the third well is not far away. Thus, all depth-dependent in-reservoir fluid geodynamic processes are visible within each well; no extrapolation away from the wells is required. Moreover, the ~30 meter oil columns in evidently connected sands are amenable to simple dynamic modeling thereby aiding in understanding. All three structures are found to have very different reservoir realizations, particualry regarding the dispositions of asphaltenes in spite of nominally similar initiation conditions after the secondary charge. That is, different reservoir fluid geodynamic processes took place producing different constraints on production in each of the structures. One well showed a light oil underlain by a tar mat. A second well showed large, disequilibrium gradients of gas-oil ratio (GOR) and asphaltene content without phase separated asphaltenes in core. The third well showed a tar mat on a shale break in the oil column not far form the GOC. There were no asphaltenes in core above the shale break and tar mat. However, below the shale break there was asphaltene throughout the core while retaining permeability, but no tar mat on the OWC. These differences were not ascribed to any paleo-OWC nor are they related to differing biodegradation. In addition, these differences are not consistent with any depressurization expalanation. To resolve the differences, a variety of data streams were used including downhole fluid analysis coupled with thermodynamic analysis from the Flory-Huggins-Zuo Equation of State (FHZ EoS) and its reliance on the Yen-Mullins model of asphaltenes. In addition, well test results provide key production information and are corroborated by vertical intereference testing on wireline. Petroleum system modeling and organic geochemical analysis of oil and core extract samples have also been very useful. The differences seen in the different wells relate to several important parameters such as the different extent of baffling which impacts both production rates as well as equilibration rates of reservoir fluids. Another key parameter is the extent of density stacking versus a lateral fluid front for the secondary light hydrocarbon charge. Proximity to the charge point enhances the lateral nature of the charge yielding rapid asphaltene instability precluding tar mat formation in sections of the well. This information is very useful when projecting reservoir properties away form wellbore.

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.

As we strive to complete more complex reservoirs, we are challenged to better understand the nature of the fluids contained within. In the North Sea, classical "black oils" are still encountered; however scenarios where volatile fluids that exhibit a bubble point are found in close proximity to fluids with dew points are not uncommon. In addition, knowing the CO2 content is paramount to completion engineering and facility design with high penalties incurred when CO2 quotas or production limits are exceeded. Characterizing these fluids is difficult. Typically wireline formation testers with fluid analyzers are used for early fluid characterization and sampling. However, with the increasing fluid complexity subtle differences need to be understood. This requires comprehensive compositional analysis, high resolution answers and quantified accuracy. This paper describes the technology and answers provided by an accurate in-situ fluid analyzer. Several case studies are discussed. In the first example oil is sampled from two depths, only a few meters apart. The in-situ fluid analysis data from these two depth, including C1, C2, C3-C5, C6+ CO2, GOR and density are compared, indicating excellent tool resolution. In addition these data are compared to laboratory sample analysis result with observed differences falling well within the quoted tool accuracies. A second example involves several closely stacked reservoirs. An in-situ compositional analysis was obtained for each reservoir fluid. By changing the flow rate of the formation tester downhole pump the flowing pressure was manipulated. This allowed to measure different ranges of bubble point pressures for each fluid. Only a few meters below a second fluid exhibiting a dew point was encountered. An indication of the fluid dew point pressure was detected by again manipulating the flowing pressure. Fluid analysis revealed compartmentalization and fluid grading through the different reservoirs in this well.

Accurate characterization of fluid and pressure regimes within a reservoir is a crucial part of the overall reservoir description process. In many offshore exploration and appraisal wells this task is performed using data acquired with wireline formation testers (WFT). Significant planning and simulation is required to properly design a WFT program. This is especially true when the anticipated environment is different from that normally encountered in the local region. Collaboration with a wider group of experts is required. Secondly, an iterative approach to the acquisition of WFT data is required, in which the results of the previous step determine the next step. This paper describes the process for WFT data acquisition within a major service company. We focus on two key aspects. First is the networked collaboration of domain experts around the world who are used as a resource for any given situation. Communication tools, sharing models, and networking options are discussed. Secondly, we examine the processes for real-time interactive communication with the wellsite and relevant stakeholders. Data transmission, real-time integration into reservoir models, and tools for operational interface are discussed. Finally we show field examples of these processes in use. In one example we document the gathering of best practices for sampling heavy oil in West Africa (heavy oil is a relatively rare occurrence in this region and sampling required the input of expertise from other regions). In a second example, we show the use of collaborative tools to optimize data acquisition for accurate reservoir characterization in the case of an exploratory well that encountered fluids very different from predrill expectations. And finally we show an example of using Interval Pressure Transient Testing (IPTT) and Vertical Interference Testing (VIT) data to economically pre-empt the acquisition of expensive DST data.

The use of wireline-conveyed formation testers for sampling, downhole fluid analysis (DFA), interval pressure transient testing (IPTT), and producibility estimation is well established in the oil and gas industry. The increasing demand for hydrocarbons is driving the exploration and production of reservoirs previously deemed uneconomical. The low-permeability limit for such reservoirs is continually being reduced while the limit for reservoir temperature is increasing. IPTT techniques address these trends by extending the limits for high-quality data acquisition.The decision on whether to perform IPTT requires an estimate of permeability. This estimate usually comes from either pretesting or other well data such as nuclear magnetic resonance (NMR) logs. However, these measurements have a shallow depth of investigation and may underestimate the mobility of the reservoir fluids because of formation damage such as fines invasion, or high-viscosity fluid in the invaded zone. To displace invaded fluids in low-permeability formations can be challenging, usually requiring a high drawdown to pump the mud filtrate and fines from the formation. High-performance packers and pumps are essential in such environments that require a large number of high differential-pressure cycles.In this paper three case studies of IPTT in low-permeability reservoirs in the North Sea are presented. In the first, pretesting with a single probe and dual-packer indicated a tight formation (no fluid communication between the tool and formation was established). IPTT was attempted and fluid moved at a drawdown of around 80 bar. The subsequent influx of formation gas reduced the drawdown significantly and a large increase in mobility was observed.In the second tight gas case study gas influx was detected, but because of the large drawdown the gas compressibility prevented a large-volume cleanup and the test was aborted. This case shows the limit of what is achievable in this environment.The third case study illustrates a very low-permeability limestone that was straddled with a dual-packer-standard-probe testing configuration. The downhole pump was equipped with a high-pressure displacement unit (DU). This pump configuration handled the high initial drawdown required to clean up the damaged zone. Initial cleanup pumping was followed by 30 hours of producing time and then a final pressure buildup. The result was a high-quality estimate of deep formation properties and fluid samples with very low contamination levels. A lesson learned was that formations considered "tight" according to data available before formation testing may be productive and capable of flowing hydrocarbons when evaluated with IPTT. Compared with the cost of a drillstem test (DST) in low permeability conditions, the dual-packer tool provided a fast, cost-efficient, and flexible way of testing individual zones.

Wireline formation testing is traditionally carried out in open-hole wells. Advances in formation tester technology have provided the industry with a new modular cased-hole formation tester (CHFT). In this new design a hole is drilled through the casing and cement, communication with the formation is then established enabling formation testing and sampling. The drilled hole is subsequently plugged. This paper describes several case-studies from the North Sea where a full range of formation testing applications (that would traditionally be performed in open-hole) were made in casing using a cased-hole formation tester. In addition to pressure testing and sampling, three recent case studies demonstrate advanced applications. The first example demonstrates zonal isolation behind casing and identifies communication between layers under injection. The reservoir consisted of two layers with significant permeability contrast. The CHFT was set at the bottom of the higher permeability zone and a hole was drilled thought the casing and annulus. The pressure was monitored while seawater was injected at increasing pressure steps into the lower permeabily zone. By analyzing the pressure response the degree of zonal communication and the maximum injection-rate were obtained. In the second example, the CHFT was used to determine whether production wells could be drilled safely, and to evaluate bypassed reservoir layers. A very deep and deviated injection well completed and perforated over a long interval was tested with a CHFT deployed by tractor. Formation testing results provided a formation pressure profile in un-developed zones and showed that the injected interval was over-pressured and above the maximum safe pressure for drilling operations. The final case study described in this paper shows an application of the CHFT for shale integrity testing. A poor cementing operation potentially left a production well without zonal isolation. The overburden shales are weak and prone to collapse. If the quality of the seal provided by the collapsed shale is tested for integrity and can be qualified as a barrier providing zonal isolation, the operator could avoid the expense of drilling a side-track. Two effective-stress testing cycles were made with the CHFT, which confirmed the integrity of the shale barrier, and quantified the minimum horizontal stress.

The increasing complexities of newly discovered reservoirs coupled with the increasing cost structure of field development mandate significantly improved and timely work flows for reservoir evaluation. Traditional modeling workflows are typically time consuming and require well organized cross disciplinary integration between geoscientists. Such models and processes are not well suited to be used and updated during formation evaluation acquisition phases of field development. In this paper a more accessible approach is proposed and demonstrated. The existing fluids model is combined with the current geologic model to construct an accurate representation of key features of the reservoir. This model is then used to predict data for a wireline formation sampling and testing tool (WFT), with emphasis on downhole fluid analysis (DFA). In this process, current reservoir understanding is tested by direct measurement in real time. If differences are uncovered between predicted and measured log data, the WFT tool is in the well, and measurements can be made to uncover the source of the error. In this paper a workflow is demonstrated where WFT DFA and PVT lab reports were used to build a fluid model after the first exploration well data was acquired. This model was then used to predict fluid properties and WFT DFA logs for a subsequent well intersecting nominally the same compartment. These DFA predictions presumed fluid equilibrium and flow connectivity. Real-time comparisons were made of predicted and measured pressures, fluid gradients, contacts and DFA data obtained from the WFT logging run. Agreement of predicted and measured log data indicates that fluid properties and reservoir connectivities used for the modeling are correct. If predictions disagree with measurements the acquisition program can be altered in real time to ensure sufficient data is acquired to understand the reservoir model inaccuracies. During the WFT logging job, this predictive model enabled validation of critical WFT data. This process also allowed testing of the reservoir connectivity. It was discovered that either compartmentalization or lateral disequilibrium of the fluids in the reservoir exists. Interpretation of the DFA data suggested that a subtle lateral disequilibrium exists and the assumption of reservoir connectivity is supported.

Wireline formation testers provide the measurements for the determination of formation pressure gradient, in-situ effective oil mobility profile, in-situ downhole fluids analysis (DFA) as well as taken PVT samples and maintaining them in single phase condition for lab analysis, interval pressure transient testing (IPTT) for characterizing of permeability anisotropy and in-situ minimum horizontal stress estimations. Pressure and fluid samples are obtained by setting a rubber packer and small diameter probe. The packer hydraulically isolates a small part of the formation from the hydrostatic pressure, while the probe enables communication between the tool and formation. This conventional technique is well suited for thick and permeable formations. However, for difficult conditions such as laminated formations or formations with low matrix permeability and formations saturated with high viscosity fluids or fractured limestones, application of a single probe technique is limited. Under these conditions, the small packer may not be able to isolate the zone, may miss a thin zone or in a formation with very low permeability and/or high fluid viscosity the contact area with the packer may be too small to let the fluid flow. To help overcome this, technique of Wireline Formation Tester (WFT) with dual packer module is used. This wireline conveyed straddle packer has the capability of hydraulically isolating a minimum of one meter of formation. The dual packer can be set repeatedly at different locations on a single trip in the well. Using these modules, pressures, real-time formation fluid identification, PVT samples, permeability and flow rate estimations can all be evaluated in detail. Within the vast Russian oil and gas fields environment with different geology, and wellbore and fluids conditions, the technique of combining probe and dual packer modules in one string and running the tool on TLC (tough logging conditions) has been applied successfully to a thinly reservoirs, formations with low permeability and unconsolidated formations saturated by high viscosity fluids (heavy oils). In this paper, application of interval pressure transient testing done during formation fluid cleaning up from mud filtrate and during downhole fluid identification is described. The main objective of using the formation tester was to take downhole representative PVT samples of high viscosity fluid in a high invasion wellbore environment in three exploration wells of a new remote field. Use of dual packer for PVT sampling and single probe and vertical observation probe together provided possibility to estimate permeability anisotropy, in spite of difficult and challenging acquisition (operations were done from Geophisika Logging unit due to the field remoteness) and wellbore conditions (well bore stability and high mud filtrate invasion).

Waterflood management requires the optimization of hydraulic fracture placement. The lack of direct stress measurements (vertical distribution and direction) in the South Priobskoe field in western Siberia has created the need to determine the orientation and magnitude of the least principal stress. The presence of impermeable shales between producing sands complicates fracturing design and field development to maximize recovery. Permeability and permeability anisotropy at different depths are unknown variables that affect well completion and reservoir management decisions. A set of wireline formation evaluation tools were used for microfracturing (stress tests) at several sand and shale formations. The stress tests were performed by isolating 1 m of formation using the dual packer module of the wireline formation tester (WFT) and creating a hydraulic fracture by injecting drilling fluid using the downhole pump. Combination of the wireline dual packer and standard probe modules provided estimates of permeability and permeability anisotropy in sands. Formation microimagery data were used before and after stress tests to obtain information on least-principal-stress direction. Challenges created by the harsh working environments in western Siberia were addressed by detailed risk assessment, job planning, and real-time quality control and decision-making. The use of the acquired stress and permeability data to optimize the number of wells, well patterns, selection of water injectors, and fracture design is discussed.