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Collaborating Authors
Results
Determining Gas Flow Rate and Formation Thermal Conductivity from Pressure and Temperature Profiles in Vertical Well
Barrett, E.. (Santos Ltd) | Abbasy, I.. (Santos Ltd) | Wu, C. R. (University of Adelaide, Australia) | You, Z.. (University of Adelaide, Australia) | Bedrikovetsky, P.. (University of Adelaide, Australia)
Abstract The gas flow rate and the formation thermal conductivity distributions along the gas well have been determined from the measured pressure and temperature profiles using production logging tools, which is much cheaper and more precise than the traditional procedures of direct flow metering. An effective and robust method is proposed in this work: the system of governing equations for non-isothermal gas flow in vertical well is solved using the Runge-Kutta method; then the flow rate and formation thermal conductivity are obtained by optimising the modelled profiles of pressure and temperature based on the measured profiles. Application of the algorithm to field case shows good agreement between the directly measured and modelled pressure and temperature profiles; the flow rate prediction is consistent with flowmeter (PLT) data; the thermal conductivity profile is also in a good agreement with that obtained from lithology log. It validates the proposed method.
- Europe (0.68)
- North America > United States > Texas (0.46)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
Abstract Injectivity decline during sea waterflooding or produced water re-injection is widely observed in North Sea, Gulf of Mexico and Campos Basin fields. The formation damage occurs mainly due to the deposition of suspended solids around injectors and the build-up the external filter cakes in the well bores. The ability to predict injectivity decline accurately is of great importance for project designs and water management. A comprehensive model that incorporates a variety of factors influencing the process is desirable for the prediction. In this paper, a new comprehensive approach for predicting injectivity decline during water flooding is proposed. The deep bed filtration is described by novel stochastic random walk equations. The injectivity decline model takes into account the reservoir heterogeneity and the distribution of solid particles by sizes. It also accounts for the later formation of the external filter cake and its erosion. A piece of software SNY is developed with the proposed model. The model is able to capture the behaviors of the injectors in the field: the initial slow injectivity decline due to the deep bed filtration of suspended particles, the later faster decline due to the build-up of the external cake, and the temporary steady state due to the cake erosion. Stronger normal dispersion or median heterogeneity close to the injector leads to farther penetration of the particles and slower impedance increase. Neglecting the particle population heterogeneity may lead to the underestimation of formation damage and predicts late transition to external cake formation. The impedance at the steady state and the starting time are highly influenced by the cake properties. The impedance and the external cake thickness at the steady state are likely to be higher in horizontal wells than those in vertical wells.
- North America > United States > New Mexico (0.24)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (2 more...)
- South America > Brazil > Campos Basin (0.99)
- South America > Argentina > Neuquen > Neuquen Basin > Chihuido De La Sierra Negra Field (0.99)
Abstract Nearly half of the remaining petroleum reserves are contained in naturally fractured reservoirs (NFR). An accurate estimate of the effective fracture permeability tensor is a key to the successful prediction of oil recovery from NFR. Standard workflows nowadays employ discrete fracture network (DFN) modeling and analytical or flow-based methods to upscale fracture permeabilities. However, DFN modeling imposes some important challenges, which can cause great uncertainty in the effective permeability tensor and subsequent recovery prediction: Analytical upscaling methods, which are commonly used due to computational efficiency, are inaccurate for poorly connected fracture networks. Flow-based upscaling methods depend on boundary conditions and are computationally expensive. Defining the optimum grid size for either method is also very difficult. In addition, DFN upscaling is often driven by practical issues such as time constrains and computational limitations, leaving little room to investigate the effects of upscaling methods and grid size. In this paper we utilize features in leading DFN simulators employed in standard industry workflows for computing effective permeability tensors with flow-based and analytical methods. We use two realistic dataset from fractured formations of onshore reservoirs in our assessment. Not surprisingly, there is up to three orders of magnitude variation in the effective permeability based on the chosen upscaling method and perceived optimum grid cell size. This has tremendous impact on predicted recovery rates and ultimate recovery; ultimately uncertainty in upscaling can mask uncertainty in the geological model. We hence introduce a new simulation technique, Discrete Fracture and Matrix (DFM) modeling, which accounts accurately for flow in the fractures and rock matrix as an efficient alternative for computing effective permeability tensors as it allows us to assess the accuracy of classical DFN upscaling approaches, which all help reducing uncertainty in recovery prediction.
- North America > United States (1.00)
- Europe (0.68)
- North America > United States > Wyoming > Big Horn Basin > NPR-3 > Tensleep Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Wall Creek Formation (0.98)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Tensleep Formation (0.98)
- (5 more...)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Communications > Networks (0.48)
On Population Diversity Measures of the Evolutionary Algorithms used in History Matching
Abdollahzadeh, Asaad (Heriot-Watt University) | Reynolds, Alan (Heriot-Watt University) | Christie, Mike (Heriot-Watt University) | Corne, David (Heriot-Watt University) | Williams, Glyn (BP) | Davies, Brian (BP)
Abstract In history matching, the aim is to generate multiple good-enough history-matched models with a limited number of simulations which will be used to efficiently predict reservoir performance. History matching is the process of the conditioning reservoir model to the observation data; is mathematically ill-posed, inverse problem and has no unique solution and several good solutions may occur. Numerous evolutionary algorithms are applied to history matching which operate differently in terms of population diversity in the search space throughout the evolution. Even different flavours of an algorithm behave differently and different values of an algorithm's control parameters result in different levels of diversity. These behaviours vary from explorative to exploitative. The need to measure population diversity arises from two bases. On the one hand maintaining population diversity in evolutionary algorithms is essential to detect and sample good history-matched ensemble models in parameter search space. On the other hand, since the objective function evaluations in history matching are computationally expensive, algorithms with fewer total number of reservoir simulations in result of a better convergence are much more favourable. Maintaining population's diversity is crucial for sampling algorithm to avoid premature convergence toward local optima and achieve a better match quality. In this paper, we introduce and use two measures of the population diversity in both genotypic and phenotypic space to monitor and compare performance of the algorithms. These measures include an entropy-based diversity from the genotypic measures and a moment of inertia based diversity from the phenotypic measures. The approach has been illustrated on a synthetic reservoir simulation model, PUNQ-S3, as well as on a real North Sea model with multiple wells. We demonstrate that introduced population diversity measures provide efficient criteria for tuning the control parameters of the population-based evolutionary algorithms as well as performance comparison of the different algorithms used in history matching.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- (2 more...)
Abstract Unconventional gas resources from low-permeability formation, i.e., tight and shale gas, are currently received great attention because of their potential to supply the world with sufficient energy for decades to come. In the past few years, as a result of industry-wide R&D effort, progresses are being made towards commercial development of gas and oil from such unconventional resources. However, studies, understandings, and effective technologies needed for development of unconventional reservoirs are far behind the industry needs, and gas recovery from those unconventional resources remains low (estimated at 10-30% of GIP). Gas flow in low-permeability unconventional reservoirs is highly nonlinear, coupled by many co-existing processes, e.g., non-Darcy flow and rock-fluid interaction within tiny pores or micro-fractures. Quantitative characterization of unconventional reservoirs has been a significant scientific challenge currently. Because of complicated flow behavior, strong interaction between fluid and rock, the traditional Darcy law may not be applicable for describing flow phenomena in general. In this paper, we will discuss a general mathematical model of gas flow through unconventional porous media and use both numerical and analytical approaches to analyze gas flow in unconventional reservoirs. In particular, we will present analytical and numerical solutions of incorporating Klinkenberg effect, non-Darcy flow with threshold pressure gradient, and flow behavior in pressure sensitive media. We will discuss the numerical implementation of the mathematical model and show applications of the mathematical model and solutions in analyzing transient gas flow in conventional reservoirs.
- Europe (1.00)
- North America > United States > Texas (0.28)
The Influence of Capillary Pressure on Phase Equilibrium of Mixed CO2-Water Injection into Geothermal Reservoirs Including Phase Appearance and Disappearance
Salimi, Hamidreza (Delft University of Technology) | Wolf, Karl-Heinz (Delft University of Technology) | Bruining, Johannes (Delft University of Technology)
Abstract We quantify the capillary pressure effect on the phase equilibrium of the CO2-water system. Our interest is in the capillarypressure range between 0 and 100 bars for temperatures between 293 and 372 K and bulk (wetting-phase) pressures between 25 and 255 bars. For this purpose, we have implemented the capillary pressure effect in the PRSV equation of state. Inclusion of capillary pressure in the phase equilibrium of the CO2-water system makes it possible to determine the capillary-pressure effect on the CO2 storage capacity and heat-energy recovery for CO2-water injection into geothermal reservoirs. We illustrate the process using a 2D model of the geothermal reservoir in the Delft Sandstone Member, below the city of Delft (The Netherlands). The process involves phase transitions between single-phase and two-phase regions. To deal with phase appearance and disappearance, we have applied a new and effective solution approach, the so-called nonisothermal negative saturation?? (NegSat) solution approach. The results show that the capillary pressure promotes evaporation. In the pressure and temperature range of our interest, capillary pressure reduces the CO2 solubility in water and the aqueous-phase density up to 64% and 1.3%, respectively, whereas it increases the water solubility in the CO2-rich phase and the CO2-rich-phase density up to 3,945% (40.5 times) and 1,544%, respectively. Capillary pressure shifts the CO2 liquid-vapor transition and consequently the upper critical point of the CO2-water system to a lower pressure. The intensity of the shift depends on the value of the capillary pressure and the bulk (wetting-phase) pressure. For instance, the CO2 liquid-vapor transition at T = 293 K occurs approximately at 60 bars for Pc = 0 bars, whereas it occurs at 15 bars for Pc = 45 bars. For mixed CO2-water injection into the geothermal reservoir (200 bars < P < 260 bars, 290 K < T < 360 K), inclusion of the capillary pressure effect in the phase-equilibrium behavior does not significantly alter the capillary CO2-trapping mechanism. In other words, CO2 banks are mainly formed in the highly permeable zones that are surrounded by less permeable zones. However, for injected CO2 concentrations close to the bubble point, the effect of capillary pressure on the phase equilibrium reduces the heat recovery by 37% and the CO2-storage capacity also by 37%. For overall injected CO2 mole fractions between 4% and 13%, the reduction in the heat recovery and CO2-storage capacity is 10%. Based on simulations, we construct a plot of the recuperated heat energy versus the maximally stored CO2 for a variety of conditions; we compare the results including and excluding the effect of capillary pressure in the phase-equilibrium calculations.
- North America > United States (1.00)
- Europe > Netherlands > South Holland > Delft (0.45)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.91)
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)
Asphaltene Deposition Study and its Effects on Permeability Reduction - A Case Study
Kharrat, R.. (Petrolum University of Technology, Tehran Research Center) | Zargar, Z.. (Petrolum University of Technology, Tehran Research Center) | Razavi, S. M. (Petrolum University of Technology, Tehran Research Center)
Abstract Asphaltene deposition affects the porosity and permeability which in turn reduces the production and raises the processing costs. Therefore, it is necessary to investigate more about the asphaltene precipitation and determining the amount of solid deposition causing the porosity and permeability reduction. In this paper, it has been tried to overcome this need by simulating the process in one of the South-West Iranian reservoirs in which asphaltene problem has been encountered frequently. The wells under production were facing severe asphaltene choking problem and coiled tubing acid wash were done every six month to remove the deposited asphaltene. Flow assurance results for the fluid are clearly saying that oil is highly asphaltic although it is a light oil. In the other hand, wells under production always are required to keep the rate as long as possible due to economic limits and it was critical for the management to know the effect of asphaltene deposition in the reservoir formation on the flow rate and vice versa. The best way to see the effect is reservoir simulation in which asphaltene deposition is modeled. First of all, the fluid model and asphaltene precipitation curve were prepared. Then, the reservoir static and dynamic models were generated based on the rock and fluid properties. The behavior of asphaltene during the production as precipitated, flocculated and deposited asphaltene were modeled using commercial software. In addition, the variation of permeability due to asphaltene deposition was obtained. Asphaltene and permeability map were generated for the entire reservoir. Most of the deposition was found to form around and nearby the production wells. Minor permeability reduction was observed throughout the reservoir; however, major damage was around the wellbore. Both precipitation and deposition amounts were visible and can be reported and this ability increases the capability to decide better about the optimum production.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (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)
Abstract CO2 capture and storage (CCS) is a technique to reduce CO2 emission, and CO2 is also used in EOR (enhanced oil recovery). It may increase oil production by 15–25% from an oil field. In this paper we present how to deal with the seismic response due to CO2 injection. To understand the seismic response due to CO2 flooding requires knowledge of the distribution of CO2 in brine, viscous loss due to CO2 and dissolution of CO2 in brine. Furthermore, the basic principle for EOR methods by CO2 is that high solubility of CO2 increases the density and lowers the viscosity at reservoir conditions of the oil, thus improving the oil mobility and the efficiency of water flooding. However, the viscous losses during the fluid flow are responsible for seismic wave attenuation. Moreover, when injecting CO2 into the water-saturated sample, some CO2 may be dissolved in the water. The Gassmann and Reuss or Gassmann and Voigt method may be used to calculate CO2 saturated seismic properties. Considering the significant differences between velocity values in these two methods, a large uncertainty is associated with fluid-saturation estimation from seismic data. I provided the rock physics model to calculate the CO2 saturated seismic properties to understand the seismic response due to the CO2 flooding. This model was tested laboratory measured data of sandstone from Lei and Xueb (2009) and carbonate from Wang et al. 1998. Modeling results provided us the viscous loss and dissolution of CO2 effects to calculate the CO2 saturated seismic properties. This model may be also used to calculate the accurate hydrocarbon production during the EOR method by CO2 injection.
- North America > United States (0.46)
- Europe > Denmark (0.29)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.50)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)