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Collaborating Authors
Phase behavior and PVT measurements
Abstract Molecular diffusion plays an important role in oil and gas migration and transport in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within a porous media. This study aims at calculating diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts on diffusion coefficient are examined. An effective diffusion coefficient that describes the diffusion behavior in a tight porous solid is estimated by using tortuosity-porosity relations as well as the measured shale tortuosity from 3D imaging techniques. The results indicated that nano - confinement could affect the diffusion behavior through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in a porous shale rock is reduce by 10 to 10 times as porosity decreases from 0.1 to 0.03.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Huron Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (18 more...)
Abstract This paper presents a simple yet rigorous model and provides a methodology to analyze production data from wells exhibiting three-phase flow during the boundary-dominated flow regime. Our model is particularly applicable to analyze production data from volatile oil reservoirs, and should replace the less accurate single-phase models commonly used. The methodology will be useful in rate transient analysis and production forecasting for horizontal wells with multiple fractures in shales. Our analytical model for efficiently handling multi-phase flow is an adaptation of existing single-phase models. We introduce new three-phase parameters, notably fluids properties. We also define three-phase material balance pseudotime and three-phase pseudopressure to linearize governing flow equations. This linearization makes our model applicable to wells with variable rates and flowing pressures. We optimized the saturation-pressure path and further suggested an appropriate method to calculate three-phase pseudopressures. We validated the solutions through comparisons with compositional simulation using commercial software; the excellent agreement demonstrated the accuracy and utility of the analytical solution. We concluded that, during the boundary-dominated flow regime, the saturation-pressure relation given by steady-state path and tank-type model for volatile oil reservoirs leads to satisfactory results. We also confirmed that our definitions of three-phase fluid properties are well suited for ultra-low permeability volatile oil reservoirs. The computation time of our model is greatly reduced compared to a numerical approach, and thus the methodology should be attractive to the industry. Our model is efficient and practical to be applied for production data analysis in ultra-low permeability volatile reservoirs with non-negligible water production during the boundary-dominated flow regime. This study extends existing analytical model methodology for volatile oil reservoirs and is relatively easy for reservoir engineers to understand.
- Asia (0.93)
- North America > Canada > Alberta (0.47)
- North America > United States > Texas (0.29)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Effect of Pore Size Heterogeneity on Hydrocarbon Fluid Distribution and Transport in Nanometer-Sized Porous Media
Zhang, Kaiyi (Virginia Polytechnic Institute and State University) | Du, Fengshuang (Virginia Polytechnic Institute and State University) | Nojabaei, Bahareh (Virginia Polytechnic Institute and State University)
Abstract In this paper, we investigate the effect of pore size heterogeneity on multicomponent multiphase hydrocarbon fluid composition distribution and its subsequent influence on mass transfer through shale nano-pores. We use a compositional simulation model with modified flash calculation, which considers the effect of large gas-oil capillary pressure on phase behavior. We consider different average pore sizes for different segments of the computational domain and investigate the effect of the resulting heterogeneity on phase and composition distributions, and production. A two dimensional formulation is considered here for the application of matrix-fracture cross mass transfer. Note that the rock matrix can also consist of different regions with different average pore sizes. Both convection and molecular diffusion terms are included in the mass balance equations, while different reservoir fluids such as Bakken and Marcellus are considered. The simulation results show that since oil and gas phase compositions depend on the pore size, there is a concentration gradient between the two adjacent pores with different sizes. Considering that shale permeability is small, we expect the mass transfer between two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix-fracture component mass transfer during both primary production and gas injection EOR as a result of confinement-dependent phase behavior. Therefore, molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection EOR simulation of heterogeneous shale reservoirs.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Performing a reservoir simulation study for hydraulically fractured horizontal wells in unconventional reservoirs relies on input parameters which are not often well defined. The uncertainty of the input parameters (i.e. completion design, petrophysics, reservoir fluid phase) leads to uncertainty in the resulting history matches and less confidence when using the model results. This paper focuses on the importance of fluid phase characterization in reservoir simulation studies. One of the challenges the industry currently faces is PVT (pressure-volume-temperature) fluid characterization for tight rock formations. When submitting a production fluid sample for analysis, it is crucial to define an accurate estimate of pressure, temperature, and gas-oil ratio (GOR) in order to place the sample in the appropriate fluid window to yield a representative PVT characterization for use in reservoir simulation studies. The case study presented in this paper describes a reservoir simulation study in the Powder River Basin with varying fluid regimes across the field (Figure 1). This particular field has three different fluid systems driven by differences in basement heat flow: black oil, volatile oil, and gas condensate. Two different reservoir simulation studies within the same field will be described in this paper. The first reservoir simulation study was developed on an unbounded well in an area of the field interpreted as black oil. The second reservoir simulation study focused on a three well pad in an area interpreted to be gas condensate. Both simulation studies had accompanying PVT reports; unfortunately, irregular early production led to uncertainty in the recombination GOR and the resulting PVT characterizations. Despite modifying several modeling parameters, the model did not respond as expected and a representative history match was difficult to achieve. By re-evaluating the fluid window and PVT conditions, the history match for wells in both studies improved substantially.
- North America > United States > Wyoming (0.86)
- North America > United States > Montana (0.62)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.67)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Effect of Saturation Dependent Capillary Pressure on Production in Tight Rocks and Shales: A Compositionally-Extended Black Oil Formulation
Nojabaei, B.. (The Pennsylvania State University) | Siripatrachai, N.. (The Pennsylvania State University) | Johns, R. T. (The Pennsylvania State University) | Ertekin, T.. (The Pennsylvania State University)
Abstract Pore sizes are typically on the order of nanometers for many shale and tight rock oil reservoirs. Such small pores can affect the phase behavior of in situ oil and gas owing to large capillary pressure. Current simulation practice is to alter the unconfined black-oil data for a fixed mean pore size to generate confined black-oil data with a depressed bubble-point pressure. This approach ignores compositional effects on interfacial tension and the impact of pore-size distribution (PSD) with variable phase saturations on capillary pressure and phase behavior. In this paper, we develop a compositionally-extended black-oil model where we solve the compositional equations (gas, oil, and water components) directly so that black-oil data are a function of gas content in the oleic phase and gas-oil capillary pressure. The principle unknowns in the variable bubble-point fully-implicit formulation are oil pressure, overall gas composition, and water saturation. Flash calculations in the model are noniterative and are based on K-values calculated explicitly from the black-oil data. The advantage of solving the black-oil model using the compositional equations is to increase robustness of the simulations owing to a variable bubble-point pressure that is a function of two parameters; gas content and capillary pressure. Leverett J-functions measured for the Bakken reservoir are used to establish the effective pore size-Pc-saturation relationship, where the effective pore size depends on gas saturation. The input fluid data to the simulator, e.g. interfacial tension (IFT), phase densities and viscosities, are pre-calculated as functions of pressure from the Peng-Robinson equation of state (PREOS) for three fixed pore sizes. During the simulation, at any pressure and saturation, fluid properties are calculated at the effective pore radius by using linear interpolation between these three data sets. In the current simulator, the reservoir permeability is enhanced to allow for opening of the fracture network by hydraulic fractures. We compare the results of the compositionally-extended black oil model with those of a fully-implicit eight-component compositional model that we have also developed. The results for the Bakken reservoir show that including PSD in the model can increase estimated recoveries by nearly 10%. We also examine the sensitivities of production to various parameters, such as wettability and critical gas saturation.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- North America > United States > Montana > Williston Basin > Elm Coulee Field > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.98)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Oil and gas reserves are the most important assets for oil companies. An accurate estimation of reserves not only helps listed oil companies prepare solid annual reserves reports required by SEC, but also guarantees the good reward from divesting assets or reasonable price to farm-in asset. A precise reserves calculation is the fundamentality for production forecast, which is vital to the sale contract, thus the feasibility of project. It controls the cash flow and most of all the sustainable development of the company. The importance of reserve estimation cannot be overemphasized whatsoever. We know that in the practice of exploration and production, all efforts are to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure and temperature. Due to the instrument sensitivity, limitation, measurement error, environmental effect, sample interval, location, the representative of sample, and Mother Nature of these properties, there is always uncertainty. In this research, a systematic study on the effects of fluid and rock properties on reserves estimation had been conducted. Effect of each property on reserves estimation is quantified through sensitivity analysis. As a result of this study, a comprehensive picture of how fluid and rock properties affect the reserves was brought to engineers. Reserves evaluator can use this to estimate the range of reserves as a consequence of uncertainty. With this study, we realized their different impacts on reserves. Therefore main efforts should go to the variables that affect the reserves most.
Abstract A reservoir study was undertaken to evaluate methods for depletion of the Rose Run formation located in the Colfax Field, Fairfield County, Ohio. The original oil-in-place and the drainage area affected by the existing wells were determined. Per well drainage areas ranged from 0.5โ22.3 acres, all significantly less than the state-prescribed 40-acre spacing for wells producing from depths greater than 4000 ft. Depletion from existing wells, new drills, a horizontal well, and waterflooding was subsequently examined, primarily through the use of black oil reservoir simulation. Introduction The Colfax Field, Fairfield County, Ohio, produces from an isolated Rose Run Reservoir pod with an areal extent measuring some 130 acres (Fig. 1). Although the first producing well in the area (Householder Unit #1) came on-line in December, 1996, it penetrated only the sands overlying the Rose Run, i.e., the Beekmantown Dolomite and Rose Run Sand Stray. The first Rose Run well, the Whetstone Unit #1, began producing in October, 1998. This study examined the primary performance of and future production opportunities for the Colfax field. The specific results of this work were the determination of:original oil and gas-in-place, recovery from existing wells and drainage area affected, potential additional recovery from new drills, potential additional recovery from horizontal drilling, potential additional recovery from waterflooding. This work was accomplished through a combination of volumetric and material balance calculations, decline curve analysis, reservoir simulation, and experience-based analysis. Geologic Description The primary production in the Colfax field is from the early Ordovician Rose Run sandstone that dips eastward at a slope of 70 feet per mile in the area. The Rose Run is overlain by impermeable carbonates which were deposited following a period of tilting and erosion. This contact forms the Knox Unconformity. The facies of the main Rose Run sand is interpreted to be from an offshore sand shoal based on sample descriptions of the five producing wells in the area and one thin section analysis (from Householder Unit #2). The main sand body has been found to be a fairly consistent 26โ30 feet thick. Neutron-density cross plot porosity values from open hole logs run on three of the wells average 16-to-18%. Water saturations calculate from 36-to-52%, increasing to the east. Sample descriptions describe this interval as a fine-to-medium grained clean sandstone. Grain sorting is moderate but variable. Quartz is the dominant framework grain; potassium feldspar is the only other significant framework grain, making up 2-to-7% of the section. Cementation is moderate and ranges from 11-to-17% with quartz overgrowths as the predominate cement. Primary intergranular porosity accounts for the bulk of the total porosity. Secondary dissolution porosity only amounts to 1-to-3% of total porosity. It has been suggested that the Rose Run reservoir is comprised of a shingled sand bar sequence running N10ยฐโ15ยฐW and dipping to the east. These bars could be 1000-to-2500 feet wide. Permeability tends to be greater north-to-south. The thicker producing areas exhibit greater porosity. A decline in reservoir properties occurs off-edge of the bars as there is a trend toward smaller grain size. This also results in an increase in water saturation, particularly on the downdip side of the bars. Reservoir Fluid The average crude oil gravity for a series of fluid samples collected from Colfax field Rose Run sand production wells measured 39.5 ยฐAPI (specific gravity 0.827) corrected to 60 ยฐF. The average initial producing GOR of three wells for which data were available was 590 scf/STB. Field observations note the produced oil is greenish in color. Black oils are characterized by initial producing GORs of 2000 scf/STB or less, a stock-tank oil gravity below 45 ยฐAPI, and a black, sometimes with a greenish cast, or brown color. Thus it can be concluded that the Rose Run crude oil may be classified as a black oil.
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.44)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.44)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (9 more...)
V.M. Shaposhnikov, SPE, and L.B. Listengarten, and S.D. Tseytlin, SPE, and L.M. Mendelevich Abstract PEn Technology was developed for high-GOR oil fields. The target was the optimization of well-formation system by means of maintenance of bottomhole pressure and supporting fluid lift. The technology applies an individual approach to each well, based on analysis of numerous parameters and data, computer simulation of well-formation system and sizing calculation for the technology's bottomhole tools. P. 371
W.D. McCain Jr., R. B. Soto, P.P. Valko, and T. A. Blasingame Abstract None of the currently proposed correlations for bubblepoint pressure are particularly accurate. Knowledge of bubblepoint pressure is one of the important factors in the primary and subsequent developments of an oil field. Bubblepoint pressure is required for material balance calculations, analysis of well performance, reservoir simulation, and production engineering calculations. In addition, bubblepoint pressure is an ingredient, either directly or indirectly, in every oil property correlation. Thus an error in bubblepoint pressure will cause errors in estimates of all oil properties. These will propagate additional errors throughout all reservoir and production engineering calculations. Bubblepoint pressure correlations use data which are typically available in the field; initial producing gas-oil ratio, separator gas specific gravity, stock-tank oil gravity, and reservoir temperature. The lack of accuracy of current bubblepoint pressure correlations seems to be due to an inadequate description of the process - in short, one or more relevant variables are missing in these correlations. We considered three independent means for developing bubblepoint pressure correlations. These are (1) non-linear regression of a model (traditional approach), (2) neural nelwork models, and (3) non-parametric regression (a statistical approach which constructs the functional relationship between dependent and independent variables, without bias towards a particular model). The results, using a variety of techniques (and models), establish a clear bound on the accuracy of bubblepoint pressure correlations. Thus, we have a validation of error bounds on bubblepoint pressure correlations. P. 267
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Even if the gas transmission occurs after the necessary processing of the gas has been completed, condensation still occurs in the natural gas transmission and/or distribution systems. The quantity of condensate formed will not only depend on composition, pressure, and temperature, but also on the unequal splitting phenomenon that takes place at T-junctions in a network system. This work investigates the splitting phenomenon in horizontal-branching-T-junctions. The compositional hydrodynamic model developed at Penn State is used to evaluate gas-condensate flow in a pipeline under steady state conditions. Using a double stream model for splitting analysis at T-junctions, the mass liquid intake fractions are determined. The junction is considered as a separator and the new compositions are calculated at the run and at the branch of the junction. Although quantitative validation of the model is limited by the lack of completeness of the available data, a reasonable qualitative match of experimental data is achieved. The results demonstrate the predictive capability of liquid route preference in two-phase natural gas/condensate flow at T-junctions. In addition to liquid split, compositional split is tested using PCB as the focal point. It is found that the concentration of PCB is distributed in direct proportion to the liquid preference route and the PCB concentration in the delivery points can be higher or lower than the inlet concentration at the supply point.