Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Civan, Faruk
Abstract The necessary and sufficient conditions of the design parameters that should be considered to build proper shale-gas reservoir simulators are investigated. The design requirements are established based on the theoretical studies of flow through extremely low permeability porous media, ion milled SEM images of the nano-geometry of shale-gas reservoir formations, laboratory petrophysical measurements, and the available production and stimulation information. This paper presents a critical discussion of the relevant aspects such as the reservoir formation structure, fluid storage and transport mechanisms, and gradual non-equilibrium motion and dynamic distribution of fluids in the pore system. Then, an overview of the capabilities of the commonly used reservoir simulation software is presented in view of the identified requirements of shale gas reservoirs. Quantitative comparisons between the alternative formulations against the conventional formulations are also presented with several examples using an in-house simulator developed in this study. Areas needing new fundamental formulations and further research for proper shale-gas reservoir modeling are delineated. This paper provides important insights and guidelines for development of adequate numerical simulators that can correctly accommodate for the proper description of the relevant phenomena, and predict gas production and water displacement in shale-gas reservoirs.
- Asia (0.68)
- North America > United States > Texas (0.68)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.99)
Abstract A two-phase modeling approach to wax gelation in shut-in submarine pipelines is presented and validated with experimental data. Accurate correlation of pressure dependence of the Wax Appearance Temperature is developed. Relevant mechanisms of wax gelation without forced convection are described in detail. Initial temperature profile of oil flowing through a pipeline under steady-state conditions is estimated based on an analytical solution obtained for turbulent flow of a single-phase system undergoing heat transfer. The natural convection phenomenon is represented by assigning a proper value to thermal conductivity of the liquid phase. Phenomenological models for transient cooling in a circular pipe cross-section and along vertical pipelines are derived. Typical simulation results indicate that prevailing pressure conditions of vertical submarine pipelines greatly affects the wax precipitation phenomenon and the relaxation of wax precipitation can be avoided by adequate insulation. Introduction A proper model for describing the waxy-oil gelation can be instrumental for effective management of the shut-in submarine pipelines because wax gelation can affect the restarting conditions significantly (Ekweribe et al, 2009). Shut-in pipelines are often scheduled for maintenance or emergency reasons. Prolonged exposure to cold surroundings may result in complete loss of production facility (Gluyas and Underhill, 2003). Therefore, appropriate modeling of wax precipitation and gelation is essential for ensuring flow assurance in submarine pipelines subject to cold sea-water temperatures. Wax precipitation and gelation is mainly driven by the thermodynamics and phase behavior induced by heat transfer occurring between the pipeline fluid and the surrounding sea-water environment. Cooling of oil due to heat loss causes the separation of heavy components, wax in particular, in the form of a crystalline structure saturated with oil. Precipitates of wax crystals may aggregate and interlock, and thus the wax/oil mixture behaves as a highly viscous gel. A solid-like state is attained when the waxy-oil is allowed to cool down over prolonged periods of time by heat loss towards the sea-water environment. Wax deposition reduces the cross-sectional area of pipeline available for flow when production is resumed or even worse if the deposited wax has effectively plugged the pipe, thus choking the pipeline to cease the flow completely. Obviously, coolest sections of pipes have the greatest potential of plugging. A submarine pipeline that has been shut-in is susceptible to complete gelation because the sea-water temperature is generally below the phase-transition temperature. A shut-in submarine pipe is a system left without the benefit of the heat supplied by the oil produced from a reservoir. Even though proper insulation may deter wax precipitation and gelation for some time, extended exposure to the low sea-water temperature conditions without such heating source may eventually induce complete wax precipitation and subsequent gelation problems. The heat loss towards the surroundings is determined by the difference in temperature between the sea-water and the pipe wall. This outward heat flow occurring at the pipe wall sets the wall temperature to be lowest in the radial direction over the cross-sectional area of the pipe. Consequently, the first wax crystals precipitate at the pipe-wall around its perimeter over any given cross-sectional area. This induces a layered aggregation of wax crystals and an inward laminar growth of the gelled wax region. The local heat capacity and thermal conductivity vary as more wax separates from the liquid oil near the wall. The wax crystals form a resistance to heat transfer once the local temperature drops to below the WAT. Consequently, the greater resistance near the pipe-wall acts as insulation for the liquid in the pipe center which is relatively warmer. Moreover, the heat loss outward to the surroundings induces more separation of wax that provides greater insulation to the center region and the crystalline growth starts to build up. This leads to a higher concentration of wax observed near the pipe-wall.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (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 > Pipelines, Flowlines and Risers > Offshore pipelines (1.00)
Abstract This study experimentally and numerically investigates formation damage induced by suspended particles in the drilling fluid and its effect on limiting their near-wellbore invasion. The study applies the NMR and X-Ray digital radiography tprovide valuable insights into damage mechanisms along the formation and depth of invasion. Formation damage caused by drilling fluids is one of the key factors for economic success in oil and gas field developments. The measured permeability reduction obtained from laboratory test by injecting particulate drilling fluid in a representative core sample is used to determine empirical parameters used to model the particle migration and deposition in porous media by means of a robust simulation of the relevant processes. The study provides a concept to develop the ability to evaluate drilling fluids in term of their formation damage potential.
Determining Effective Fluid Saturation, Relative Permeability, Heterogeneity and Displacement Efficiency in Drainage Zones of Oil Wells Producing Under Waterdrive
Toth, Janos (University of Miskolc) | Bodi, Tibor (University of Miskolc) | Szucs, Peter (University of Miskolc) | Civan, Faruk (University of Oklahoma)
Summary A convenient, practical method is applied for rapid analysis and interpretation of after-water-breakthrough history of oil wells producing under waterdrive for determination of effective fluid saturation, relative permeability, heterogeneity and displacement efficiency. Formulation and methodology are presented for the characterization of parameters of radial unsteady-state flow of oil and water through producing-well drainage regions in oil reservoirs. Validity and capabilities of this approach for diagnosis of conditions in production-well drainage zones in waterdrive reservoirs are confirmed by analysis of typical oil field case scenarios. The present approach is proven to yield significant information of practical importance that can be used for effective selection of potential enhanced oil recovery (EOR)/improved oil recovery (IOR) methods for oil reservoirs.
- Europe (1.00)
- North America > United States > Texas (0.93)
Abstract Current simulators make assumptions that may be inappropriate for modeling shale gas reservoirs. These assumptions are: 1) that the system exhibits instantaneous capillary equilibrium, 2) that transport can be completely defined by viscous flow (Darcy's law), and 3) that relative permeability is not flow rate dependant. To investigate these assumptions, a one-dimensional reservoir simulator was developed. This was then modified to implement a solution that does not force instantaneous capillary equilibrium and the effects of this phenomenon were studied. In this paper, the requirements for a realistic shale gas simulator are first reviewed and results from a model study of a shale gas reservoir using a commercial simulator are briefly discussed. A simple example illustrates why instantaneous capillary equilibrium may be inappropriate and therefore justifies the need to develop simulators that do not make the above assumptions. The mathematical formulation used to implement a non-equilibrium capillarity model is developed and discussed. Lastly, a set of simulation studies are discussed where saturation profiles for two-phase flow displacement are compared for capillary equilibrium and non-equilibrium conditions. We also investigate the effect of wettability by considering a 100% water-wet and a 100% oil-wet formation. The results indicate a dramatic impact on the saturation profiles produced by relaxing the capillary equilibrium requirement.
Abstract We evaluate an improved method based on a non-Darcy flow model for the determination of intrinsic permeability from laboratory pressure-pulse measurements. Our approach distinguishes between the apparent and intrinsic permeability based on a model-assisted analysis of experimental flow data; the gas motion is described by considering the prevalence of different regimes, such as viscous, slip, transition, and free molecular flow conditions based on the Knudsen number criterion, under different rock, fluid, and flow conditions. This approach is applied to the experimental data obtained from pressure-pulse decay tests. The improved model is more rigorous than the previous models, provides more detailed insights, and can be used reliably for analysis and interpretation of a variety of experimental pressure-pulse tests, especially those peformed on shales.
Abstract Rigorous modeling of wax deposition in submarine oil pipelines undergoing a cooling process after shut-in is developed. Relevant mechanisms of wax deposition are described by accurate approaches. Fraction of wax precipitated under various conditions is estimated by an improved correlation and validated using experimental data. It is proven that consideration of a moving boundary between waxy gel and liquid oil is unnecessary and consideration of wax/oil mixtures as a continuously varying multiphase system is more effective. Introduction Wax appearance inside pipelines is an important phenomenon for transportation of hydrocarbon fluids where the temperature of the surroundings is below the phase-transition temperature. Particularly, submarine pipelines designed for flow of liquid hydrocarbons may experience precipitation of wax under shut-in conditions. Although such pipelines are usually properly insulated for preventing wax appearance and related problems, prolonged exposure to cooler environments may cause sufficient drop in temperature favorable for inducing wax separation from the liquid oil phase. After shut-in of a submerged pipeline, potential of complete wax separation is created by the cooler submarine environment. Wax and liquid oil usually form a highly viscous gel characterized by a solid-like structure. Thus, wax deposition may reduce the cross-sectional area of pipeline available for flow (choking) when the production operations are resumed or even worse if the deposited wax has effectively plugged the pipe. Obviously, coolest sections of pipes have the greatest risk of plugging. Several experimental studies have demonstrated that wax separation is mainly driven by thermodynamic interactions in systems containing hydrocarbons. Cooling due to heat loss in the liquid oil causes the separation of heaviest components (wax) in the form of a crystalline structure saturated with oil. Pressure drop at dynamic and static conditions has almost no effect on wax precipitation. Change in pressure induces little wax appearance because waxy crystals are incompressible and liquid hydrocarbons are slightly compressible. A large pressure differential is required to alter the specific volume, and thus change the mass fractions in both waxy crystals and the liquid hydrocarbon. However, the shear stress induced by flowing conditions plays a significant role in wax deposition. Shear stress causes erosion on the waxy layers deposited around the pipe wall. Therefore, the thickness of layered deposition reaches a plateau owing to equilibrium between growth and erosion under flowing conditions. Wax appearance causes a significant change in the nature of hydrocarbons. For instance, the behavior varies from Newtonian to non-Newtonian. For a cylindrical container or a cross-section of a pipe, the temperature does not remain constant in the radial direction after the wax separation has already taken place. Difference in physical properties between the various phases keeps the center warmer than the outer perimeter (wall). Consequently, waxy crystals are more abundant near the wall. Thus, particle aggregation in the form of layers (wax deposition) is observed first near the wall. Wax deposition progresses towards the center of the container as the fluid becomes cooler. Accurate prediction of the wax fraction is very important in modeling wax deposition inside pipelines. Comprehensive models considering thermodynamic interactions between the solid and liquid phases during wax deposition are still in development. Some compositional models have shown adequate prediction of wax appearance and the phase mass fractions (Zuo and Zhang, 2008, Coutinho, 2000). However, application of these models for simulation purposes requires a high computational effort. A more convenient approach is to develop an empirical correlation suitable for capturing the behavior of the wax mass fraction against temperature predicted by a compositional analysis or measured directly in experimental tests.
Summary Conditions leading to the plugging of perforations in wells and pore throats in porous formations are investigated experimentally. Accurate correlations are developed for the effect of pore throat to particle size ratio on flowing fluid conditions and plugging time leading to particle bridging. It is demonstrated that the critical pore throat to particle size ratio vs. particle-volume fraction Reynold's number can be correlated satisfactorily using an exponential function, and the dimensionless plugging time vs. reciprocal particle-volume fraction yields an exponential-type correlation. Such empirical correlations can be used to determine and alleviate the conditions that induce perforation and pore plugging by migrating particles in petroleum reservoirs. These correlations reveal that the critical pore-to-particle diameter ratio below which plugging occurs may be greater than the unit physical limit. Introduction Plugging of perforations in wells and pores of porous formations occur frequently during various operations of oil and gas industry, including water flooding, drilling, perforation, and workover. Particles migrating at sufficiently high concentrations with a particle to hole size ratio may form bridges across and narrow down the perforations and pore throats, reducing the flow rate through reservoirs. This may cause severe damage to the productivity of the oil and gas wells. Hence, the operational conditions need to be adjusted to avoid the plugging of pores and perforations by suspended particles. The mechanism of pore-throat plugging in porous formations is of interest in geotechnical engineering and the petroleum industry. Pore-throat plugging can occur by size exclusion or by the jamming of fine particles during fluid flow. Migration and entrapment of fine particles during flow in petroleum reservoirs can lead to clogging and decreased oil productivity. The pore throats control the rate of flow through the interconnected pore space inducing a gate or valve effect (Chang and Civan 1991).
- Europe > Norway > Norwegian Sea (0.44)
- North America > United States > Texas (0.28)
Summary A comprehensive review of literature concerning wax crystallization, deposition, and gelation, as well as the yielding behavior of waxy crude gels during pipeline restart is presented. Detailed experimental investigation of the temperature and pressure effects on gel strength is carried out. Influence of testing temperature on gelation kinetics is studied using a controlled stress rheometer (CSR), and the data is analyzed by applying a modified Avrami model for isothermal crystallization. The effect of system pressure on restart conditions is studied using a model pipeline system. It is observed that this system provides the best reproducibility of yield pressures. The model pipeline results are compared with the yield point tests obtained on a CSR. The results of the experimental work reported in this paper suggest that weaker gels may be formed at higher shut-in pressures, which is a favorable condition for pipeline restarting operations. Introduction A critical operational problem involving subsea pipeline transport of waxy crude is the safe restarting of flow after shut-in for a period of time. The impact of pressure during gelation of waxy crude is of great practical interest, especially for a subsea pipeline connected to long vertical risers as shown in Fig. 1. This is an issue of utmost practical importance because most crude oil found in many parts of the world, including the North Sea, Middle East, Australasia, North Africa, West Africa, Alaska, Indonesia, and China, are of waxy types. Earlier concepts of waxy crude oils assumed that they were derived from terrestrial or higher plant source materials. However, these oils can also be originated from lacustrine and marine sources. These crudes contain high molecular weight n-paraffin (waxes), mostly in the range from C18- C65. Wax content of crude oil has been reported to be as low as 1% in south Louisiana and as high as 50% in Altamont, Utah. Under hot reservoir conditions, waxy crudes behave like Newtonian fluids. However, upon experiencing cold temperatures for some time on the sea floor lower than the wax appearance temperature (WAT), the heavy paraffin (mainly straight chains) may precipitate from the oil and render the crude a non-Newtonian flow behavior. The wax molecules precipitated within the oil may subsequently deposit over the pipe wall as a layer of a gel-type material. This, in turn, reduces the effective cross-sectional area available for flow of crude oil and, in worst cases, can completely clog the pipeline. The detrimental consequence of such incidences is that these pipelines may have to be abandoned eventually if proper wax mitigation measures are not taken or are not economically feasible under given conditions. This paper investigates the consequences of quiescent cooling process of waxy crude to temperatures below the gel-point at conditions encountered in subsea environments. Obviously, this is actually the worst case scenario in waxy oil flow assurance issues where different phases of wax transformation during cooling are inherent, namely wax precipitation, deposition, and gelation. In addition, the yielding behavior of the gel becomes a matter of interest during the restart of such gelled pipelines. Hence, for a comprehensive understanding of the overall problem, the different stages of waxy crude evolution during cooling are considered, highlighting key efforts made to elucidate each process. In addition, the necessity to incorporate system pressure effects on gelation into restart models is argued upon and the experimental results supporting this viewpoint are discussed and presented.
- Africa (1.00)
- North America > United States > Louisiana (0.34)
- Europe > United Kingdom > North Sea (0.24)
- (5 more...)
Summary Naphthenate-soap deposition and the related formation damage in petroleum reservoirs are investigated by means of laboratory-scale experimental and theoretical studies. Experiments were carried out in three directions to understand and quantify the naphthenate-soap-deposition problem. Static bottle tests were conducted to determine the precipitation rate for various pH and temperature conditions. Microscopy investigations were carried out to verify the growth of naphthenate-soap particles under different pH conditions. Core-flow tests were conducted to generate naphthenate-soap particles and to determine the permeability impairment caused by subsequent deposition of these particles in porous media under flowing conditions and different pH values. A power-law expression was proposed and verified for the precipitation rate of the naphthenate-soap particles. The parameters of the rate equation were correlated with respect to pH and temperature. This also allowed the determination of the critical pH value for the onset of naphthenate-soap precipitation. The results of the particle-size experiments were described by a particle-growth equation, and the parameters of the equation were correlated with respect to pH. The core-flow experiments proved the occurrence of formation damage caused by naphthenate-soap precipitation and subsequent deposition. The permeability impairment in core-flow experiments was described by a new differential model. The applications presented in this study provide insights for understanding the mechanism and magnitude of naphthenate-soap-induced formation damage and help in taking proper measures to avoid the formation damage caused by naphthenate-soap deposition.