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to

Go**Summary**

Paraffin deposition under single-phase flow conditions was investigated to determine its dependence on shear stripping, deposit aging, flow regime, temperature gradient, and fluid properties.

In this study, a new model for the prediction of single-phase wax deposition has been developed. Most of the models previously used assume that equilibrium exists at the deposit-fluid interface. A kinetic resistance of the fluid is considered in the new model. Therefore, the interfacial-wax concentration might be different from the equilibrium-wax concentration. The model also includes continuous diffusion of wax into the deposit. We believe that this enrichment of the deposit is responsible for the increasing hardness of the deposit with time - a process known as "aging." The effect of shear stripping may also be incorporated in the prediction.

The model predictions are compared with predictions from previous models, as well as with experimental data gathered at the Tulsa U. Paraffin Deposition Projects, with two different oils: a black oil and a condensate. Even though some tuning is required for each type of oil, the new model is based on physical phenomena, reducing the empiricism of previous models.

asphaltene inhibition, asphaltene remediation, flow assurance, hydrate inhibition, Hydrate Remediation, improvement, oilfield chemistry, paraffin remediation, Production Chemistry, production control, production logging, production monitoring, remediation of hydrates, Reservoir Surveillance, scale inhibition, scale remediation, single-phase paraffin deposition modeling, Upstream Oil & Gas, wax inhibition, wax remediation

SPE Disciplines:

- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.80)

A unified model of multiphase heat transfer is developed for different flow patterns of gas-liquid pipe flow at all inclinations from -90Â° to +90Â° from horizontal. The required local flow parameters are predicted by use of the unified hydrodynamic model for gas-liquid pipe flow recently developed by Zhang *et al*.^{1,2} The model prediction of the pipe inside convective heat transfer coefficients are compared with experimental measurements for a crude oil/natural gas system in horizontal and upward vertical flows, and good agreement is observed.

Artificial Intelligence, coefficient, Comparison, convective heat transfer coefficient, correlation, gas core, gas-liquid pipe, heat, Horizontal, liquid film, model, prediction, production control, production logging, production monitoring, Reservoir Surveillance, slug, slug body, transfer, Upstream Oil & Gas

SPE Disciplines: Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)

A Probabilistic/mechanistic modeling was carried out to develop a predictive model for fully developed slug length distribution in horizontal pipeline. Statistical analysis suggested the appropriateness of a Log-Normal model over an Inverse Gaussian model for predicting slug length distribution. A total of 64 data sets were used to empirically correlate the Log-Normal model. Two empirical relationships for mean slug length and slug length standard deviation were developed. A statistical analysis revealed that, in addition to pipe diameter and mixture velocity, volumetric flow rate of the liquid film in the bubble region and the momentum exchange between the slug body and the liquid film are strongly correlated to mean slug length at a 5% significance level. The slug length standard deviation was found to have a significant correlation with film liquid holdup and momentum exchange. A model validation study demonstrated the capability of the probabilistic/mechanistic model to reproduce the experimental data with a satisfactory match. The match was improved when the developed correlations were tuned using the statistical confidence intervals of their coefficients.

Artificial Intelligence, coefficient, confidence, diameter, distribution, error, function, Horizontal, independent variable, Inverse Gaussian, machine learning, management and information, model, pipeline transient behavior, regression, regression model, slug, slug catcher, slug length distribution, slug length standard, Standard Deviation, Upstream Oil & Gas

SPE Disciplines:

Technology:

Paraffin deposition under single-phase flow conditions was investigated to determine its dependence on shear stripping, deposit aging, flow regime, temperature gradient and fluid properties.

In this study, a new model for the prediction of single-phase wax deposition has been developed. Most of the models previously used assume that equilibrium exists at the deposit-fluid interface. A kinetic resistance of the fluid is considered in the new model. Therefore, the interfacial wax concentration might be different from the equilibrium wax concentration. The model also includes continuous diffusion of wax into the deposit. We believe that this enrichment of the deposit is responsible for the increasing hardness of the deposit with time, a process known as aging. The effect of shear stripping may also be incorporated in the prediction.

The model predictions are compared with predictions from previous models, as well as with experimental data gathered at the Tulsa University Paraffin Deposition Projects with two different oils: a black oil and a condensate. Even though some tuning is required for each oil, the new model is based on physical phenomena, reducing the empiricism of previous models.

aspect, concentration, condition, deposit, deposit growth, deposit thickness, deposition, Drop, effect, equilibrium, fraction, glycol, interface, model, paraffin, prediction, production control, production logging, production monitoring, Reservoir Surveillance, shear, Singh, test, Thickness, Upstream Oil & Gas

SPE Disciplines: Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)

The effects of pressure on flow pattern transition boundaries for crude oil-natural gas two-phase flow were investigated.

Experimental observations of flow patterns were carried out for different pressures (200 and 450 psia) and inclination angles (horizontal, +1 degree and vertical). Special attention was given to the stratified-intermittent transition and the intermittent-annular transition for horizontal and inclined flow, and the transition to annular flow for vertical flow, since these boundaries were known to be sensitive to pressure. A schematic diagram of the chilling system is shown in Fig. 7. the purpose of the chilling system is to control the pipe wall temperature of the test section. The schematic diagram of the heating section is shown in Fig. 8. The heating system can circulate glycol through the heater to warm the oil before it enters the mixing tee.

The experimental results show that pressure affects the stratified-intermittent transition for horizontal flow and slightly affects the intermittent-annular transition for inclined flow and for vertical flow. The predictions of transition boundaries by existing mechanistic flow pattern prediction models show good agreement for all transition boundaries described above.

annular, capacitance, capacitance sensor, condition, crude oil-natural, dimensionless voltage, high pressure condition, Horizontal, instability, liquid film, liquid slug, pattern, pipe, prediction, production control, production logging, production monitoring, reservoir description and dynamics, Reservoir Surveillance, signal, transition, transition boundary, Upstream Oil & Gas

SPE Disciplines:

**Summary**

A mechanistic model was developed to predict flow pattern and flow characteristics such as pressure drop and liquid holdup in vertical and deviated wells. The model includes five flow patterns: bubbly, dispersed-bubble, slug, churn, and annular flows.

Flow-pattern prediction incorporates the transition models proposed by Barnea^{1} (or Taitel *et al*.^{2}) for dispersed-bubble flow, Ansari *et al*.^{3} for annular flow, Tengesdal *et al*.^{4} for churn flow, and a new bubbly-flow transition model. For each predicted flow pattern, a separate hydrodynamic mechanistic model is proposed. A new hydrodynamic model for bubbly flow has been developed, and the Chokshi^{5} slug-flow model has been modified significantly. The Tengesdal *et al*. and Ansari *et al*. models have been adopted for churn and annular flows, respectively.

The model is evaluated with a well databank of 2,052 cases covering a broad range of field data. Pressure drop predictions with the model are also compared with those using the Ansari *et al*., Chokshi, Hasan and Kabir,^{6} and Tengesdal^{7} mechanistic models, and the Aziz *et al*.^{8} and Hagedorn and Brown^{9} correlations. The results of the comparison study show that the proposed mechanistic model performs the best and agrees with the data.

annular, Artificial Intelligence, Bubble, bubbly, calculation, case, correlation, Drop, fraction, gradient, mechanistic model, model, pattern, pipe, production control, production logging, production monitoring, psi, Reservoir Surveillance, Tengesdal, transition, Tulsa, Upstream Oil & Gas, well, well case

SPE Disciplines: Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3-6 October 1999.

annular, Artificial Intelligence, Bubble, bubbly, case, comprehensive mechanistic modeling, correlation, Drop, evaluation, fraction, gradient, model, pattern, pipe, prediction, production control, production logging, production monitoring, psi, reservoir description and dynamics, Reservoir Surveillance, slug, Tengesdal, transition, Upstream Oil & Gas, well, well case

SPE Disciplines:

**Summary **

A general horizontal well friction factor expression was developed using the principles of conservation of mass and momentum. Horizontal well friction factor correlations were developed based on theoretical analysis and a large amount of experimental data. It was observed that the friction factor for a perforated pipe with fluid injection can be either smaller or greater than that for a smooth pipe, depending on influx to main flow rate ratios. The proposed friction factor correlation can be used in any horizontal well model that considers pressure variation along the wellbore.

**Introduction **

The most commonly used assumptions in studying horizontal well production behavior are: infinite conductivity and uniform influx. Infinite conductivity assumes no pressure drop along a horizontal well, and uniform influx assumes that the influx from the reservoir is constant along a horizontal well. It has been argued in the literature that the infinite conductivity wellbore assumption is adequate for describing flow behavior in horizontal wells. Although this may be a good assumption in situations where the pressure drop along the horizontal section of the wellbore is negligible compared to that in the reservoir, it is also reasonable to expect the friction and acceleration effects to cause noticeable pressure drops in long horizontal wellbores.

In a horizontal well, depending upon the completion method, fluid may enter the wellbore at various locations along the well length. The distance between perforations may not be sufficient to achieve a stabilized velocity profile, and this may lead to different pressure behavior than for fully developed flow. The pressure distribution in a horizontal well can influence the well completion and well profile design, as well as having an impact on the production behavior of the well. Therefore, both the pressure drop versus flow behavior along the well and the relationship between the pressure drop along the well and the influx from the reservoir need to be understood.

Flow behavior in porous wall pipes or plates has been studied by several investigators^{1-5} in other disciplines. Although they provide useful information for the study of horizontal well flow behavior, the results cannot readily be applied in the petroleum industry.

The petroleum industry started to investigate horizontal wellbore hydraulics in the late 1980s. Investigators conducted analytical or experimental studies to investigate different aspects of horizontal well flow behavior.^{6-10} A friction factor correlation for horizontal wellbores was proposed by Asheim *et al.*,^{6} which includes accelerational pressure losses due to continuous fluid influx along the wellbore. However, the literature survey reveals that experimental data are limited and theoretical studies are inconclusive for predicting frictional pressure loss in horizontal wells.

In this study, an experimental and theoretical investigation of the flow behavior in a horizontal pipe with fluid injection from a single injection point in the pipe wall and from multiple injection points in the pipe wall with perforation densities equivalent to 1, 2, and 4 shots/ft has been conducted. New correlations based on acquired experimental data were developed for the prediction of friction factors in a horizontal wellbore.

**Model Development **

A general model was developed to predict horizontal well friction factors. Consider an incompressible fluid flowing isothermally along a uniformly perforated pipe of cross section *A*. The area of each perforation is *A _{ p}*. Fluid is injected through the perforations into the main flow stream uniformly as illustrated by

For the three terms on the left hand side of Eq. (1), assume that average properties completely define the flow field. The first two terms on the right hand side of the equation use the average velocities by introducing momentum correction factors *B*_{1} and *B*_{2} which are defined by the following equation: $$B={1\over AV^{2}}\,{\int {A}}v^{2}\,{\rm d}A,\eqno ({\rm 2})$$ where *v* and *V* are the velocity distribution and average velocity in cross section *A* respectively.

The last term of Eq. (1) represents the acceleration of flow resulting from fluid injection. When the injected fluid enters the main flow stream through the perforations, the streamlines change directions. Each local mean velocity is tangent to the streamlines and can be divided into two components; *v _{r}* and

This paper was prepared for presentation at the 1998 International Petroleum Conference and Exhibition of Mexico held in Villahermosa, Mexico, 3-5 March 1998.

capacitance sensor, correlation, distribution, facility, frequency, liquid holdup, Multiphase, pipeline, production control, production logging, production monitoring, Reservoir Surveillance, sensor, slug, slug characteristic, slug frequency, slug liquid, slug translational, test, transducer, Tulsa, Upstream Oil & Gas

Oilfield Places: North America > United States > Alaska > North Slope > Prudhoe Bay Oil Field (0.99)

**Summary**

Weep holes have been used widely to detect the presence of liquefied petroleum gases (LPG's) in brine for underground, compensated storage systems. When the brine level drops below the weep hole, LPG product enters the brine-production system, causing an increase in both tubinghead pressure and flow rate. To prevent cavern overfill, a cavern shutdown is initiated when LPG in the surface brine system is detected by pressure or flow instruments at the tubing head.

This study investigates the multiphase-flow characteristics of weep-hole LPG-detection systems to correctly estimate the operating limits. A simple and easy-to-use model has been developed to predict the tubinghead-pressure and flow-rate increases. The model can be used to implement safer and more efficient operation procedures for underground, compensated LPG-storage systems.

This paper presents model predictions for a typical field case. An analysis of weep holes as product-detection devices for LPG-storage reservoirs has been carried out. It was found that the increases in pressure and flow rates at the tubing head change as a function of the product's injection flow rate. Therefore, a thorough consideration of cavern operating parameters is necessary to evaluate the use of constant pressure and flow-rate values to initiate emergency shutdown of the cavern.

Introduction

Long-term demand variations require large storage volumes of LPG. These seasonal demand variations can be satisfied in two ways: peak-load plants that can quickly be brought into operation and shut down; and underground storage, if naturally occurring reservoirs exist in the region of interest. For economical reasons, gas utility, pipeline, production, and consumer companies store gaseous fuels underground all over the world.1

Gas storage is primarily used to supply the increased fuel needed for space heating in cold weather. Depleted gas reservoirs, aquifers, salt cavities, and mined caverns have been used for gas storage. Storing hydrocarbons in cavities that were created in salt formations by means of solution mining was first conceived in Germany during World War I. In the 1950's, the use of salt cavities for storing propane and butane underground was introduced.2 Underground LPG storage reached 125 million bbl in the U.S. by 1966, and 560 million bbl by 1983.3 Depleted oil and gas reservoirs are designed for one injection-and-withdrawal cycle per year. Aquifer storage fields are more costly to develop and operate, and also generally support one injection-and-withdrawal cycle per year. Salt caverns, although more expensive to develop, have high deliverability rates and can offer six or more injection-and-withdrawal cycles per year.

There are two possible cavern-operating configurations: compensated (with brine) and uncompensated (without brine) systems. Uncompensated caverns depend on gas-pressure changes in the cavern as would occur during gas storage, and this depends on the ability of the cavern salt structure to resist salt creep. To prolong the life of a salt cavity, high-pressure operations are desirable. For high pressures, the brine-compensated system has advantages. LPG is stored in either the liquid- or dense-phase state. In brine compensation, the two liquids, LPG and brine, displace each other; LPG displaces brine on injection, and brine displaces LPG on withdrawal.3

Weep holes have been used widely to detect the presence of LPG in brine for compensated storage systems. When the brine level drops below the weep hole, LPG product enters the brine-production stream and causes an increase in both tubinghead pressure and flow rate. To prevent cavern overfill, a cavern shutdown is initiated upon detection of LPG in the surface brine system by pressure or flow instruments at the tubing head.

Although weep holes have been used to detect the presence of LPG in brine for underground, compensated storage systems, there is no available technique to predict emergency-shutdown tubinghead pressures and flow rates for safe operation.

Current practice in the industry is to use predetermined constant values of tubinghead-pressure and flow-rate increases to initiate the emergency shutdown of a storage cavern. The applicability of the constant limits of pressure and flow rate for the emergency shutdown of a storage cavern needs to be investigated.

The main objective of this study is to develop a simple and easy-to-use simulator to predict the multiphase-flow behavior and potential operating difficulties associated with LPG storage in salt caverns.

Modeling

Fig. 1 gives a typical configuration for a compensated cavern storage system. LPG is injected into the cavern through the annulus between the casing and the tubing. LPG displaces brine and brine is produced through the tubing. The weep hole is situated at a short distance above the tubing shoe. If the brine level drops below the weep hole, a small amount of LPG product starts entering the brine-production stream through the weep hole. As the LPG rises in the tubing along with the brine, it is exposed to changes in pressure and temperature. Two-phase flow occurs when the pressure and temperature in the tubing reach the bubblepoint pressure and temperature of the LPG. Tubinghead pressure can be expressed as

Equation 1

The creation of a gas phase in the tubing causes the elevational pressure drop to decrease, despite the increase in frictional pressure drop caused by higher flow rates. Considering the small amounts of LPG present in the tubing, frictional pressure drop increase is not expected to compensate for or exceed the decrease in elevational pressure drop. Therefore, an increase in both pressure and mixture flow rate is anticipated at the tubing head. There is no available model to predict the tubinghead pressure and flow rate for LPG storage wells. Here, we present a simple model to predict the multiphase-flow behavior of LPG-storage systems in compensated salt caverns.

Compositional Analysis of LPG.

Knowledge of the phase behavior of a multicomponent fluid mixture is an essential part of understanding the flow behavior of systems involving light hydrocarbons. The COMPUFLASHä,4 simulator was used for performing vapor/liquid-equilibrium (VLE) calculations and to predict pressure/volume/temperature (PVT) properties of the LPG product. Fig. 2 shows the phase diagram of demethanized LPG as an example. Similar phase diagrams can be generated for the other grades. Table 1 gives the composition of the demethanized LPG.

Behavior, Brine, case, cavern, Engineering, gas monetization, head, increase, injection, liquified natural gas, LNG, LPG, lpg-storage system, petroleum, petroleum engineering, production control, production logging, production monitoring, PVT measurement, reservoir description and dynamics, Reservoir Surveillance, SPE Production, tubinghead, Upstream Oil & Gas, weep hole, weep-hole diameter

SPE Disciplines:

- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (1.00)

Thank you!