Range Of Water Cuts Research Articles

Research on transparency of coal mine geological conditions based on distributed fiber‐optic sensing technology

AbstractCoal mining induces changes in the nature of rock and soil bodies, as well as hydrogeological conditions, which can easily trigger the occurrence of geological disasters such as water inrush, movement of the coal seam roof and floor, and rock burst. Transparency in coal mine geological conditions provides technical support for intelligent coal mining and geological disaster prevention. In this sense, it is of great significance to address the requirements for informatizing coal mine geological conditions, dynamically adjust sensing parameters, and accurately identify disaster characteristics so as to prevent and control coal mine geological disasters. This paper examines the various action fields associated with geological disasters in mining faces and scrutinizes the types and sensing parameters of geological disasters resulting from coal seam mining. On this basis, it summarizes a distributed fiber‐optic sensing technology framework for transparent geology in coal mines. Combined with the multi‐field monitoring characteristics of the strain field, the temperature field, and the vibration field of distributed optical fiber sensing technology, parameters such as the strain increment ratio, the aquifer temperature gradient, and the acoustic wave amplitude are extracted as eigenvalues for identifying rock breaking, aquifer water level, and water cut range, and a multi‐field sensing method is established for identifying the characteristics of mining‐induced rock mass disasters. The development direction of transparent geology based on optical fiber sensing technology is proposed in terms of the aspects of sensing optical fiber structure for large deformation monitoring, identification accuracy of optical fiber acoustic signals, multi‐parameter monitoring, and early warning methods.

A Novel Model for Forecasting Production Performance in Waterflood Oil Reservoirs

The importance of production performance forecasting in reservoir development and economic evaluation cannot be overstated. Previous models have shown deficiencies in accurately predicting production performance, necessitating the development of a new semianalytical model to enhance its application scope and prediction accuracy. This study proposes a novel semianalytical model based on the Buckley–Leverett (BL) equation and a newly proposed linear relationship between outlet water saturation and average water saturation, as well as Willhite’s formula of oil/water relative permeability. The results demonstrate the universality of this new model, as it can generate three equivalent log‐linear relations, including the previously proposed model. Sensitivity analysis confirms the applicability of the model in various reservoirs. In addition, both model and field case studies highlight the advantages of this technique in forecasting water cut and cumulative oil production, with an extensive application scope covering over 90% of the water cut range. A comparison of oil production prediction results from six different predictive methods reveals that the proposed semianalytical model exhibits the lowest error rate of −0.01%. Moreover, the semianalytical model can be utilized to directly solve for the approximate values of the exponents in Willhite’s oil/water relative permeability equations. In summary, this novel semianalytical forecasting model demonstrates a robust ability to forecast water cut, cumulative oil production, and recovery efficiency.

Oil-Water Flowing Experiments and Water-Cut Range Classification Approach Using Distributed Acoustic Sensing

Summary The accurate measurement of dynamic water cut is of great interest for analyzing reservoir performance and optimizing oilwell production. Downhole water-cut measurement is a very challenging work. Moreover, the surface-measured water cut is a comprehensive indicator of commingled producing well and it is difficult to use this parameter to deduce the downhole water cut of each contributing layer. In this paper, we propose to use distributed fiber-optic acoustic sensing (DAS) technology for the classification of water-cut range. DAS can dynamically monitor the entire wellbore by “listening” to the acoustic signals during flow. A large number of laboratory experimental data from DAS have been collected and analyzed using wavelet time scattering transform and short-time Fourier transform (STFT). The extracted low-variance scattering feature, short time-frequency feature, and fusion feature (combination of two extracted features) were learned with backpropagation (BP) neural network, decision tree (DT), and random forest (RF) algorithm. Then, a classification method of water-cut range in oil-water flow was established with machine learning. Field DAS data were collected from two oil wells to verify the effectiveness of the proposed method. The classification accuracies for the vertical well (Well A) are 92.4% and 87.4% by DT and RF model, respectively. For the horizontal well (Well B), the average classification accuracy exceeds 90% for all three methods. Water shutoff measure was conducted in Well B, and an obvious water decrease was realized. The result shows that the fusion feature overweighs single feature in machine learning with DAS data. This study provides a novel way to identify downhole water-cut range and detect water entry location in horizontal, vertical, and deviated oil-producing wells.

Application of Microwave Transmission Sensors for Water Cut Metering under Varying Salinity Conditions: Device, Algorithm and Uncertainty Analysis.

The measurement of water cut in crude oil is an essential procedure in petroleum production and it is desirable to obtain these data through an automatic and real-time method. Microwave sensors can be used for the task, and they are safe, robust and can cover the whole water cut range. However, they are relatively susceptible to the water conductivity and temperature, and the algorithms for addressing these problems are still rare in the literature. In this paper, a microwave transmission sensor that can measure the water cut under varying salinity conditions is proposed, and the algorithm for solving the water cut and salinity simultaneously with the measured amplitude and phase is described in detail. Experiments under different water cut and salinity conditions are conducted, and the results are used to verify the model and algorithm. Finally, a simplified and fast method for uncertainty analysis is proposed and applied to the iteration algorithm under test conditions. It can be concluded that accuracy higher than 95% in the water cut measurements can be expected under the 0~100% water cut range, and an error of about 10% in the water conductivity is achievable under water-continuous flow conditions. The uncertainty analysis shows that the calculated water cut and salinity results are negatively correlated, and the water salinity uncertainty tends to be larger than the water cut uncertainty. When the water salinity is high, the water cut uncertainty tends to be high whereas the water salinity uncertainty tends to be low.

Water Cut Measurement of Horizontal Oil–Water Flow Using Trielectrode Capacitance Sensor

From the actual development and testing requirements of horizontal wells in domestic oilfields, according to the problems that the common sensors have relatively low resolution during the water cut measurement for the oil–water flow in the horizontal wells with medium and low production, a trielectrode capacitance sensor (TECS) is designed and a water cut measurement system based on TECS is developed for different conditions of horizontal oil–water flow. Specifically, the electrostatic field distribution of the annular measurement region is investigated under different conditions of horizontal stratified flow. Then, its equivalent capacitance on the electrodes is analyzed. Based on the simulated results, the effects of structural parameters on sensitivity distribution are analyzed, including the electrode length, the radius of the flow channel, and the thickness of the insulation, determining its optimal structure. Moreover, the static and dynamic experiments, as well as the field testing, validate the designed TECS, indicating that the TECS enables measuring the water cut of horizontal oil–water flow, especially under low flow rate and oil–water stratified conditions. The developed TECS could realize the water cut measurement with a wide flow rate range (3–60 m <inline-formula xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink"><tex-math notation="LaTeX">$^3$</tex-math></inline-formula> /d) and the full water cut range (0%–100%) for the horizontal oil–water flow.

Measurement of Water Holdup in Vertical Upward Oil-Water Two-Phase Flow Pipes Using a Helical Capacitance Sensor.

Oil–water two-phase flows widely exist in industrial production, especially in the petroleum industry. The liquid holdup is significant for understanding reservoir production characteristics and improving oil recovery. This paper focuses on the helical capacitance sensor for the measurement of water holdup of oil–water two-phase flows. A new double helix capacitance sensor with an electrode rotation angle of 360° is designed. The sensitivity field distribution of the sensor with different parameters is simulated by the finite element analysis method, and the optimal geometric size of the sensor is obtained. The measurement characteristics of the sensor under different flow conditions are investigated by dynamical experiments of vertical oil–water flows. By analyzing the response signal of the helical capacitance sensor, the flow pattern can be identified, and the apparent water holdup can be calculated. The results show that the proposed sensor is suitable to measure the water holdup in a wide range of water cuts. Even in flow conditions of a high water cut, the sensor still retains good resolution in the D O/W flow pattern. This study expands the water holdup measurement of a capacitance sensor in the case of an oil–water two-phase flow with a high water cut.

Ultra Low Power Sensor for 3-Phase Water-Cut Applications

Precise measurement of the water fraction in oil is of critical importance in the oil industry. Currently, cost-effective, reliable, and compact downhole measurement technologies capable of full-range three-phase measurements are not available. This article presents an ultra low power, low cost, wireless, and noncorrosive resonance sensor based on magnetoelastic technology that has been implemented by an amorphous ribbon and electromagnetic interrogation. The proposed technology enables distinguishing all three gas, water, and oil phases with amplitude changes of 75% and 99% and resonant frequency shifts of 0.46% and 3.88%, respectively, compared to the gas phase. The response of the sensor enables characterizing the water-cut range from 10% to 90%. The addition of a Teflon anticorrosion layer enables sensor deployment for extended periods of time in harsh environments.

Effect of salt and water cuts on hydrate anti-agglomeration in a gas condensate system at high pressure

Anti-agglomerants (AAs) can be effective molecules in gas hydrate flow assurance in deep-water at high subcooling conditions. Salt and water cut (ratio of water volume to total liquid volume) may have a major effect on hydrate anti-agglomeration. The understanding of the effect of salt and water cut on hydrate anti-agglomeration is limited. There has been no systematic investigation of anti-agglomeration in water-cuts in the 10 to 100% range in rocking cell apparatus at high pressure. In this work, we conduct a systematic investigation of the effect of NaCl and water cut on the performance of a non-ionic anti-agglomerant which is effective at high water cuts (up to 100%). We use a condensate liquid as the liquid hydrocarbon phase and methane as hydrate former to conduct a systematic investigation of the effect of water cut and salt on anti-agglomeration at high pressure. At a low water cut of 10%, the salt makes the AA ineffective. At 20% water cut, NaCl does not have an appreciable effect on AA performance. In water cuts in the range of 30 to 100%, 1wt% AA becomes effective when there is limited amount of NaCl in the aqueous phase. The effect of NaCl includes lowering of water to hydrate conversion and decreasing the solubility of AAs in water. At 95% water cut the mixtures of condensate, salt, water/brine, and AA form a very viscous emulsion. Addition of alcohol allows anti-agglomeration in this complex mixture. The measurements over a broad range of water cuts reveal formation of water-in-oil and oil-in-water emulsions as well as flocculation. To shed light on the mechanisms we perform emulsion studies and measure AA partitioning between the aqueous phase and the hydrocarbon phase. This study presents the mechanisms that their understanding may be essential in application of AA in a broad range of water cuts.

Dynamic characterization of a low cost microwave water-cut sensor in a flow loop

Inline precise measurement of water fraction in oil (i.e. water-cut [WC]) finds numerous applications in oil and gas industry. This paper presents the characterization of an extremely low cost, completely non-intrusive and full range microwave water-cut sensor based upon pipe conformable microwave T-resonator. A 10″ microwave stub based T-resonator has been implemented directly on the pipe surface whose resonance frequency changes in the frequency band of 90MHz–190MHz (111%) with changing water fraction in oil. The designed sensor is capable of detecting even small changes in WC with a resolution of 0.07% at low WC and 0.5% WC at high WC. The performance of the microwave WC sensor has been tested in an in-house flow loop. The proposed WC sensor has been characterized over full water-cut range (0%–100%) not only in vertical but also in horizontal orientation. The sensor has shown predictable response in both orientations with huge frequency shift. Moreover, flow rate effect has also been investigated on the proposed WC sensor’s performance and it has been found that the sensor’s repeatability is within 2.5% WC for variable flow rates.

Effect of intermediate wettability nanoparticles on oil-water emulsion stability

Emulsions are ubiquitous in oil production operations and in general undesirable for various reasons. These include increased pressure losses leading to reduced oil productivity, pipeline and other equipment corrosion, as well as separation difficulties resulting in increased production costs. Surface active agents (also known as surfactants, like asphaltenes, resins, etc.) and solid particles (for example clays) are naturally present in crude oils. These components can act as stabilizers for oil and water emulsions. Therefore in order to mitigate the aforementioned problems related to emulsions, a better understanding of how emulsions are formed and stabilized is essential. This study focuses on nanoparticle stabilized emulsions and aims to contribute to a deeper understanding as it pertains to the effect of solid nanoparticles on the stability of oil and water emulsions.More specifically, the objective of this research is to investigate the separation kinetics of oil-water emulsions stabilized by spherical silica nanoparticles of intermediate wettability and its dependence on solid particle concentration, initial dispersion phase, water-cut, and shearing time. A novel, state-of-the-art, Portable Dispersion Characterization Rig (P-DCR) is used to run the experiments (as compared to the conventional bottle test method) and the relevant software for accurate data acquisition. All tests are conducted at ambient pressure and temperature conditions. Mineral oil and distilled water are used as the test fluids. The initial oil to water ratio in the batch separator is an important parameter. Therefore a broad range of water-cuts is tested. Starting with a 25% water-cut the experimental results indicate that in most cases no emulsion forms and complete phase separation takes place fast. However, when the water-cut increases to 50% and 75% a stable emulsion rag layer phase is always formed and full separation is not achieved within the experimental time frame. For the stirring times examined, faster separation takes place when the nanoparticles are initially dispersed in the oil phase. Using the specific type of nanoparticles, the formation of multiple emulsions (oil in water in oil, O/W/O) is observed. In general, as the nanoparticle concentration increases the rate of the separation process decreases. The size of the solid nanoparticles is also a critical factor and although not studied intentionally, it is inferred from the results that larger particles do not stabilize the formed emulsions as efficiently as smaller particles do.

Investigation of hydrate plugging in natural gas+diesel oil+water systems using a high-pressure flow loop

To investigate hydrate plugging processes and hydrate plugging mechanisms, a high-pressure flow loop was newly designed and constructed where hydrate plugging experiments were performed from natural gas+diesel oil+water systems for a range of water cuts (30–100%) and initial liquid flow rates (1600–2400kgh−1). Based on the experimental data of hydrate morphology and flow parameters, hydrate formation and distribution characteristics in the flow loop were analyzed and two hydrate plugging processes together with the corresponding hydrate plugging mechanisms were proposed. For gradual hydrate plugging, the plugging process can be divided into four stages. Formation and growth of a hydrate deposition layer is the governing plugging mechanism. For rapid hydrate plugging, the plugging process can also be divided into four stages. Liquid stratification and a sharp increase in viscosity is the governing plugging mechanism for rapid hydrate plugging. In addition, silt-like hydrates and flocculent-like hydrate deposition layer were observed in gradual plugging experiments, whereas slurry-like hydrates with no obvious deposition layer were observed in rapid plugging experiments.

A comparison of the rheological behavior of hydrate forming emulsions stabilized using either solid particles or a surfactant

Simple clathrate hydrates are non-stoichiometric, ice-like crystalline compounds that can, among other things, cause blockages of oil and gas pipelines. More challenging exploration and development has emphasized the need to investigate the rheological behavior of hydrates in order to ensure continuous production of crude oil through pipelines especially for solid stabilized emulsions. Therefore, a difference in the rheological behavior of hydrate forming water-in-oil emulsions stabilized using either solid particles (Aerosil R974, fumed silica particles) or a surfactant (Span 80, a non-ionic surfactant) over a range of water cuts is investigated. A rheometer with helical ribbon geometry was used to investigate the rheological behavior of hydrate slurries as opposed to conventional standard geometries. Cyclopentane was used as the hydrate-forming component. The results showed that hydrate formation was rapid in the presence of solid particles compared to surfactant. We hypothesize that solid particles act as nucleation sites and reduce the induction time required for hydrate formation. In addition, the viscosity of water-in-oil emulsions increased with an increase in water cut. Hydrate forming emulsions formed using solid particles had a higher viscosity than emulsions formed using surfactant.

Anti-agglomeration of natural gas hydrates in liquid condensate and crude oil at constant pressure conditions

An effective anti-agglomerant (AA) can reduce capillary force between hydrate particles to prevent them from sticking together, therefore preventing the blockage in pipelines. In recent studies, we have reported an AA formulation which shows high effectiveness at low dosage in methane/natural gas hydrates over the entire water-cut range. All our past work, however, was conducted in a closed rocking cell system with n-octane as the hydrocarbon liquid phase. In this work, we investigate the effectiveness of an improved formulation in various systems at constant high pressure (∼100bar natural gas) and high cooling rate (−8°C/h) over the water-cut range of 30–80%. Condensate liquid and crude oil are used as the hydrocarbon liquid phase. Because of the impact of the acidic gases in natural gas, a small amount of lithium hydroxide is included in the new formulation. Lithium hydroxide is more efficient than sodium hydroxide which was used in our previous studies. The dosage is reduced by ∼40% by mass. We demonstrate the effectiveness of improved AA formulation in an extensive set of measurements. The effect of salinity on the AA effectiveness is also investigated. It is found that increasing salinity can decrease the dosage of base chemical in the formulation significantly.

Insights into the formation mechanism of hydrate plugging in pipelines

Experiments from three-phase (natural gas+water+diesel oil) flow systems were performed in a flowloop to study the hydrate formation and plugging mechanisms from data on morphology and flow characteristics. The hydrate plugging mechanism was investigated for a range of water cuts (5–80vol%) and the injection of chemical additives (glycol and Inhibex 501). The results from the flowloop experiments demonstrated that water and oil formed a disperse system in which water formed a three-dimensional network, separating oil into a mass of oil droplets before hydrate formation; when hydrate began to form, the water network converted into a hydrate network and formed a very sticky oil-in-hydrate network system; With the hydrate formation, some of the oil was squeezed out of the network and the oil-in-hydrate network system shrank, precipitated from the oil phase, and deposited onto the pipe wall, and finally formed hydrate plugging. The presence of glycol or Inhibex 501 did not change the formation mechanism of hydrate plugging, while it decreased the hydrate formation rate.

Prediction of Frictional Pressure Gradient in Horizontal Oil/Water Dispersion Flow

SummaryA novel model has been developed for the prediction of frictional pressure gradient in unstable turbulent oil/water dispersion flow in horizontal pipes. This model uses the friction-factor approach, based on the law of the wall, to predict the pressure gradient. Modification of both the von Karman coefficient κ' and the parameter B' have been carried out in the law of the wall to include the effect of the dispersed phase—namely, the dispersed-phase volume fraction and the characteristic-droplet-size diameters. The developed model applies to both dilute and dense flows, covering the entire range of water cuts. Model predictions have been compared with a comprehensive experimental database collected from literature, resulting in an absolute average error of 9.6%. Also, the comparisons demonstrate that the developed model properly represents the physical phenomena exhibited in unstable turbulent oil/water dispersions. These include drag reduction, increase in frictional pressure gradient with increasing dispersed-phase volume fraction, and the peak in the frictional pressure gradient at the oil/water phase-inversion region.

Integration of impedance measurements with acoustic measurements for accurate two phase flow metering in case of high water-cut

Previous studies have yielded promising results as to the use of impedance measurements in two phase flow metering in estimating the flow rate of individual flows in oil fields (i.e. water and oil flows). However, most of these approaches are not accurate in the case of high water-cut or within the water-cut range 40% to 60%, where the mixed liquid is neither a good conductor, nor a good insulator. With the increased out-aging of the oil fields, these two ranges are usually dominant which require the usage of new methods. This paper presents a new non-radioactive probe which combines acoustic measurements with the impedance measurements to accurately provide in real-time the flow rate of each individual flow within the whole water-cut range. A dedicated pattern recognition algorithm using a neural network and relying on the physical properties of the fluid dynamic has been implemented. Experimental measurements performed on a laboratory scale two phase flow loop show that the proposed flow meter can in fact become a competitive two phase flow meter, since less than 5% relative error could be achieved for the whole water-cut range.

An Accurate Machine for Real-Time Two-Phase Flowmetering in a Laboratory-Scale Flow Loop

<para xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink"> A new flow measurement system for real-time flow computation of a two-phase flow in an oil field is described. The system utilizes an array of ultrasound sensors together with capacitance and conductance sensors to accurately interpret the fluid composition in the whole water-cut range. The flow rate is determined using venturi and differential pressure techniques. A dedicated hierarchical neural network algorithm that relies on the various physical properties of the fluid was implemented and tested in a laboratory-scale flow loop. Experimental results demonstrated that real-time classification within a <formula formulatype="inline"><tex Notation="TeX">$\pm$</tex></formula>5% relative error in volumetric flow regardless of the flow regime or the fluid composition can be achieved. This is an improvement over traditional systems, where weak accuracy is usually obtained either within the 40%–60% water-cut range or in the case of a high water cut. </para>

An Investigative Study of Potential Emulsion Problems Before Field Development

Summary Before the development of a field, it is worthwhile to determine the characteristics of crude-oil emulsions. This may be even more important if the wells are to be equipped with electricalsubmersible pumps (ESPs) which can create a shearing environment resulting in tight emulsions. One such study was conducted to determine the characteristics of emulsions from a cluster of oil fields planned for development. The proposed development is to produce from three fields and several different reservoirs. The central processing facility (CPF) will process ≈500,000 B/D oil and 50,000 B/D of water. Previous studies determine the impact of ESP on emulsions and on the ESP design (horsepower) and the possibility of demulsifier injection downhole. The emulsion properties are also necessary for the design of central wet crude handling facilities. A series of emulsion tests was conducted with crudes from different reservoirs at bottomhole and surface temperatures, range of water cuts, and shearing conditions. The results are provided in terms of "relative" tightness of emulsions from different reservoirs. The viscosities of various emulsions were also determined. The results indicate that demulsifier injection facilities will be needed at the wet crude handling facilities and possibly in wells from one reservoir that has a high asphaltenic and viscous crude. This paper provides a framework of laboratory emulsions studies that can provide valuable information for the design of CPFs before they are built. This paper also discusses some practical aspects of demulsifier treatment programs, including demulsifier selection and optimization and methods to prevent emulsion problems.

Asphaltene Induced W/O Emusilon: False or True?

Tight brine‐in‐oil emulsions and related high viscosities are common oil field problems experienced in mid‐ to late‐life. Emulsions can have a detrimental effect on water separation efficiency, and costs for injection equipment and demulsifier chemicals are high. It is commonly assumed that asphaltenes play a dominant role in emulsion formation, although in some crudes it was found that resins play a role in emulsion formation, especially the carboxylic acids. For the asphaltenes, polarity, and crude oil aromaticity play an important role in their interactions at the oil‐water interface, and to a lesser degree the brine pH. For the resins, pH plays an important role, as carboxylic groups are mostly active when de‐protonated. In this article, we studied the role of asphaltenes in oil/water emulsions by application of Critical Electrical Field measurements in topped oil and de‐asphalted topped oil. The emulsion stability was measured for a range of water cuts (from 2 to 60%), brine pH, temperature, and shear rates.

Downhole Fiber-Optic Flowmeter: Design, Operating Principle, Testing, and Field Installations

SummaryThis paper discusses the design, operating principles, flow-loop testing, and initial field installations of the world's first all-fiberoptic flowmeter for downhole deployment. The flowmeter provides real-time measurement of the flow rate, phase fraction, pressure, and temperature. It is deployed with the production tubing and is rated to 125°C and 15,000 psi. It is fullbore, nonintrusive, electrically passive, has no moving parts, and overcomes the design limitations imposed by downhole environments. Thus, it has the potential to provide highly reliable downhole measurements. The flowmeter has been tested extensively in industrial flow loops in a wide range of conditions. Results from the testing have demonstrated the flowmeter's ability to measure flow rates and water fractions in oil/water systems to within ±5% for the entire range of water cuts. These results have been validated by data from several field deployments.