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Collaborating Authors
Drillstem/well testing
Abstract Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in identifying gas bearing zones. While gas identification in metric reservoirs can be normally achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less and even advanced petrophysical logs struggle in discriminating gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds are often overpressurized and pressures are supercharged due to low mobility. A new wireline formation testing approach for thin beds to discriminate gas from water zones was introduced, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. This provided the possibility of testing very low permeability zones with high uncertainties in saturations. Dual packer tests were also successfully carried out in the underlying shale formation never considered before a real reservoir, revealing potential for gas production. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well tests, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves, reducing at the same time uncertainties in reservoir model. Four jobs with dual packer and downhole fluid analysis to test thin beds were performed so far in Barbara NW, Barbara and Clara Fields, resulting in added gas reserves estimated in 2 Billions Sm3 and gas production higher than the one at fields startup several years ago. This is a remarkable result for development wells in a mature environment (balanced exploration), maximizing asset value. Based on these results, several gas fields producing today from metric reservoirs will be revisited in the very near future in order to start production from thin beds, untouched until now, with the advanced wireline formation testing approach described in this paper playing a key role.
- Europe > Italy (0.52)
- North America > United States > Texas > Wichita County (0.24)
- North America > United States > Texas > Archer County (0.16)
- Europe > United Kingdom > North Sea > Central North Sea (0.16)
- North America > United States > Texas > Fort Worth Basin > Barbara Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Clara Field (0.98)
Investigation of the Applicability of Thermal Well Test Analysis in Steam Injection Wells for Athabasca Heavy Oil
Ghahfarokhi, Ashkan Jahanbani (Norwegian University of Science and Technology (NTNU)) | Jelmert, Tom Aage (Norwegian University of Science and Technology (NTNU)) | Kleppe, Jon (Norwegian University of Science and Technology (NTNU)) | Ashrafi, Mohammad (Norwegian University of Science and Technology (NTNU)) | Souraki, Yaser (Norwegian University of Science and Technology (NTNU)) | Torsaeter, Ole (Norwegian University of Science and Technology (NTNU))
Abstract Thermal well testing of steam injection wells offers an inexpensive quick method to estimate flow capacity and swept volume in thermal recovery processes. Pressure falloff tests are commonly used for this purpose. Estimation of steam zone properties and swept volume from falloff test data in this study is based on the theory assuming a composite reservoir with two regions of highly contrasting fluid mobilities and the interface as an impermeable boundary. Consequently, the swept zone acts as a bounded reservoir for a short duration, during which the pressure response is characterized by pseudo steady state behavior. The purpose of this study is to evaluate the applicability and accuracy of thermal well test analysis method and effects of different parameters on results. Pressure falloff testing is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Different gridblock models are considered. Viscosity of Athabasca heavy crude sample was measured in the lab using a rotational viscometer up to 300°C. Bitumen sample molar mass was measured by cryoscopy. Density at standard conditions was measured by a density measuring cell. These data were used as input for numerical simulation purposes. Results of this work show that the swept volume, swept zone permeability and skin factor can reasonably be estimated from pressure falloff tests. The effects of gravity, dip, permeability anisotropy and irregular shapes of swept zones are studied. It can be seen that these factors do not greatly affect the estimated results. Results of 3D models show that the estimation of permeability and steam swept volume depends on the vertical positions where pressure data are measured. It is also found that real gas analysis does not substantially improve the calculation accuracy and the pressure analysis technique suffices for all practical purposes.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Harmonic pulse testing is a well testing technique in which the injection or production rate is varied in a periodic way. The pressure response to the imposed rates, both in the pulser well and in the observer wells, can be analyzed in the frequency domain to evaluate the reservoir properties. The advantages of this type of test are that dedicated well testing surface equipment is not required and that the test can be performed during ongoing field operations. In an earlier study we demonstrated that the harmonic pulse testing methodology can be used to evaluate the effective permeability to hydrocarbons and the reservoir total compressibility even for such a heterogeneous case as in a water injection scenario. The analysis can be performed using a numerical simulator in the Fourier domain, by which heterogeneities can be explicitly taken into account. As time-stepping is not required in such a simulation, calculations are much faster than calculations in the time domain. In the present paper we report on the application of the methodology to two field cases. The first case is a gas storage reservoir, operated with a day‒night injection‒shut in scenario. Data analysis proved that the reservoir was homogeneous and that a minor fault identified by the seismic was not hindering hydraulic communication between the pulser and the observer wells. The second case is a set of harmonic test experiments on three groundwater wells, the details of which have been published earlier together with a first attempt to interpret the data. The previous analysis was based on the hypothesis of homogeneous formation, but could not consistently explain all the measurements. With our novel methodology it was possible to investigate the effects of heterogeneity and we demonstrated that the presence of a fault zone with reduced permeability may explain the observations.
- Geology > Geological Subdiscipline > Geomechanics (0.49)
- Geology > Structural Geology > Fault (0.34)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
An Engineering Approach to Utilize Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in Well Testing and Sand Stone Matrix Stimulation - First Time in the World
Shaheen, Tarek (Schlumberger) | El Rahman, Sayed Abd (GPC) | Anwar, Emad (GPC) | Dilling, Lambert (Schlumberger) | Noya, Vidal (Schlumberger)
Abstract For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd. An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements. This paper describes the first application of FOTECT in sandstone formations, involving: The sandstone matrix stimulation operation. Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation. Accurate depth correlation to achieve optimum placement of the treatment fluids Monitor the chemical reactions in real time of the engineered treatment fluid. Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions. Qualitative production allocation of the interval as a response to the treatment fluids Evaluation of the skin value real-time while executing matrix stimulation. Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries). The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.
- Europe (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.28)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract The concept of depth of investigation is fundamental to well test analysis. Much of the current well test analysis relies on solutions based on homogeneous or layered reservoirs. Well test analysis in spatially heterogeneous reservoirs is complicated by the fact that Green’s function for heterogeneous reservoirs is difficult to obtain analytically (Deng and Horne 1993). In this paper, we introduce a novel approach for computing the depth of investigation and pressure response in spatially heterogeneous and fractured reservoirs. In our approach, we first present an asymptotic solution of the diffusion equation in heterogeneous reservoirs. Considering terms of highest frequencies in the solution, we obtain two equations: the Eikonal equation that governs the propagation of a pressure ‘front’ and the transport equation that describes the pressure amplitude as a function of space and time. The Eikonal equation generalizes the depth of investigation for heterogeneous reservoirs and provides a convenient way to calculate drainage volume. From drainage volume calculations, we estimate a generalized pressure solution based on a geometric approximation of the drainage volume. A major advantage of our approach is that the Eikonal equation can be solved very efficiently using a class of front tracking methods called the Fast Marching Methods (FMM). Thus, transient pressure response can be obtained in multimillion cell geologic models in seconds without resorting to reservoir simulators. We first visualize depth of investigation and pressure solution for a homogeneous reservoir with multi-stage transverse fractures and identify flow regimes from pressure diagnostic plot. And then, we apply the technique to a heterogeneous reservoir to predict depth of investigation and pressure behavior. The computation is orders of magnitude faster than conventional numerical simulation and provides a foundation for future work in reservoir characterization and field development optimization.
- Europe (0.94)
- North America > United States > Texas (0.48)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in Copenhagen, Denmark, 4-7 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In this paper, we present the interpretation of pressure transient well test data from discretely fractured reservoirs, where the fractures provide conduits for fluid flow and displacement, but where the fracture network is poorly connected. For this reason, dual porosity models such as Warren and Root's formulation are not usually applicable. We first outline the gaps in the existing pressure transient well test interpretation methodology for these reservoirs, then we introduce two new techniques developed to address these gaps: 1) a reservoir model-based inversion technique for the identification of spatial variation in reservoir parameters from pressure transient data, and 2) a boundary-element method for determining the pressure transient behavior of the reservoir with arbitrarily distributed finite and/or infinite conductivity vertical fractures. Using these two new techniques, we defined a new integrated interpretation methodology for reservoirs with discrete natural fractures and incorporating openhole log data, seismic, and the preliminary geological reservoir model. This is an important step in reconciling static and dynamic reservoir data to update the geological reservoir model with meaningful parameters. This methodology provides a direct means of calibrating the fracture model with the well test pressure and rate measurements-one of the few dynamic and deep-reading measurements for reservoir evaluation. Finally, we illustrated the use of the methodology, and demonstrated its robustness by using an example DST from a fractured carbonate reservoir in Campos Basin, Brazil.
- South America > Brazil (0.86)
- Europe > Denmark > Capital Region > Copenhagen (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Structural Geology > Fault (0.68)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract In digital oil fields in which intelligent completions are used, information that can be provided by the intelligent completion technology is increasing in importance, as intelligent well completions can minimize the need for additional custom data-gathering solutions. Thus, industry-data interfacing standards for multiple devices and systems can be reduced. For assets using intelligent completions, solutions are attained by a combination of subsurface and surface or subsea sensors provided by several vendors. Challenges arise when attempting to manage the interfaces required for providing real-time data from all points of interest (i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings, etc.). The design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance is the focus of this paper. The asset optimization applications acquire operating parameters from all points of interest, making them available to software modules designed to estimate key wellperformance indicators. The asset-optimization application discussed here is an integrated system that performs five services: A data-interfacing methodology acquires data from multiple sources or directly from downhole devices. The integration service converts the subsurface and surface data to engineering units of measured well parameters. The well performance service uses well PVT and device-integration service values to execute complex calculations, like virtual flow metering, water-cut estimates, etc. The human/machine/interface service provides visualization, trending, and querying. The connectivity service facilitates structured data transfer to field historians. The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that include more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
- Europe (0.46)
- North America > United States > Texas (0.28)
- Africa > Nigeria (0.28)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OPL 217 > Agbami-Ekoli Field > Agbami Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OPL 216 > Agbami-Ekoli Field > Agbami Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.98)
- (6 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- (2 more...)
Abstract Laboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions. Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate due to degradation of the polymers during the injection process. In addition, polymers exhibit non-Newtonian behaviours resulting in different viscosities of the polymer solutions depending on the shear rate in the reservoir. For the Austrian reservoir, water injection fall off tests were available. A simulation model was calibrated with these tests, and used to simulate injections of polymer solutions followed by fall offs. Simulation results indicate that water injection and fall off tests followed by a series of polymer injection and fall off tests can be interpreted to determine the in-situ viscosity of polymer solutions and the radius of the polymer front with reasonable accuracy, even in the case of non-Newtonian shear-thinning behaviour. Being able to determine the in-situ viscosity allows modifying the injection programme (changing pumps, modifying perforations) if the degradation of the polymer viscosity is found to be significant, and adjusting the polymer concentration to improve stability and efficiency of the displacement process.
- North America > United States > California (0.46)
- North America > United States > Oklahoma (0.28)
- Europe > Austria > Vienna (0.28)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The Statfjord field entered into the blow down phase after 30 years of production. Production of injection gas and gas liberated from residual oil is the main production target in this phase. In some areas, the gas cap has been produced and the wells are producing mainly water until the solution gas is mobilized. These wells have gone through large changes in gas-liquid-ratio (GLR) and water-cut (WCT). Production tests from wells located in such areas have been used when analyzing the ability of multiphase-flow correlations to model vertical lift performance (VLP). Accurate modeling of the VLP is critical to predict a realistic production rate during the blow down phase. Measured wellhead (THP) and downhole pressures from about 80 production tests, from four wells, were used to analyze the accuracy of VLP correlations at widely varying flow conditions (GLR, WCT, and THP). Altogether 17 multiphase pressure drop correlations incorporated in the program Prosper were tested by comparing observed and calculated downhole pressures. Based on the production tests the ability of the different correlations to predict the VLP varies with the following top 4: Hagedorn Brown, Petroleum Experts, Petroleum Experts 2, and Petroleum Experts 3. These correlations are recommended if no measured data is available. In general a somewhat low pressure drop is predicted at low gas-liquid ratio (GLR), and a somewhat high pressure drop is predicted at high GLR. After tuning, accurate predictability was observed for the different correlations for limited ranges in GLR e.g. 50-300 Sm3/Sm3. However, for larger ranges in GLR it was not possible to achieve an accurate VLP correlation, even after tuning. Hagedorn Brown and Petroleum experts seem to be the most accurate correlations for a wide range of producing GLR. The error in the predicted production performance when a single VLP correlation is used can be substantial for highly productive wells with large variations in producing GLR. It is recommended to shift the tuning following the GLR development.
- North America > United States (0.93)
- Europe > Norway > North Sea > Northern North Sea (0.71)
- Europe > United Kingdom > North Sea > Northern North Sea (0.61)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.99)
- (2 more...)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- (2 more...)
Abstract The focus of this study is on the investigation of multiphase flow effects on the pressure transient analysis in layered reservoirs with cross flow. Virtually all studies on the subject of multiphase well test analysis have been carried out in single layer reservoirs. However, many reservoirs are found to be composed of number of layers whose characteristics are different from each other and the wells in such reservoirs may be completed and produced from more than one layer. A novel technique is proposed based on replacing multi-phase multi-layer reservoirs with cross flow with an equivalent single phase single layer reservoir. To validate the proposed method, several reservoirs with different saturations were studied numerically and were compared with the results of the proposed model. The reservoir parameters such as phase mobilities, skin factor and average reservoir pressure are compared with actual values. It was found that reservoir parameters can be obtained accurately with the equivalent single phase single layer model. However, care should be exercised when horizontal saturation gradient is significant.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)