Liquid Blockage Research Articles

Performance of dual-row condenser using microplate and conventional folded multiport extruded tube: A prospective pilot study

Microchannel heat exchangers (MCHXs) are typically manufactured using multiport extruded tubes and serpentine louvered fins, which exhibit deficiencies in corrosion resistance. Tubes made of multilayered aluminum have been shown to improve the corrosion performance. This study explored the thermal–hydraulic performance of a novel microplate heat exchanger (MPHX) with a dual-row design that utilizes advanced materials such as multilayer aluminum through comparison with conventional folded MCHXs. The results indicate that the heat transfer rate of the dual-row MPHX was at most 30 % higher compared to that of conventional folded MCHX for the same frame size. However, heat transfer of the MPHX was approximately 10 % lower than that of the conventional folded MCHX for the same effective face area. Additionally, the conventional folded MCHX is highly sensitive to the installation orientation and flow configuration; it fails to function when installed vertically and in co-current flows owing to issues such as liquid blockage. Such phenomena were not observed in the dual-row MPHXs. On the refrigerant side, the MPHXs exhibited pressure drops that were three to four times higher than that of a conventional folded MCHX.

Experimental research on the reflection and response characteristics of pressure pulse waves for different gas pipeline blockage materials

AbstractNatural gas pipelines are exposed to complex production and transportation environments, leading to blockages of varying compositions and forms due to various factors. This paper proposes a pressure pulsing wave‐based pipe blockage detection method, and a series of pipeline blockage detection experiments of different materials are carried out, including hydrate blockage, ice blockage, paraffin blockage, and water blockage. Through the blockage detection calculation theory and the reflection and transmission characteristics during pressure wave emission, the blockage position, length, and section blockage rate under different blockage materials are obtained, and the influence of different blockage materials on the reflection and transmission signal characteristics of the pressure pulse wave is analyzed. The results show that the solid blocking material does not noticeably impact the reflectivity and reflective properties of pressure waves, and different cross‐sectional shapes have a noticeable impact on the reflectivity of the pressure wave. The reflected wave waveform of the liquid blockage material is visible but irregular. The average error of blockage location is 0.78%.

Eccentricity effect on horizontal capillary emptying

This paper theoretically studies the effect of eccentricity on the conditions of capillary emptying (determined by critical Bond number) in a horizontal annular tube in a downward gravity field. Experiments are conducted to compare with theoretical results. We find that non-horizontal eccentricity can lead to the occurrence of a re-entrant liquid-state transition (from liquid non-occlusion to liquid plug to liquid non-occlusion) with increasing Bond number, when the eccentricity (e) or inner-to-outer radius ratio (χ) is large enough, and the two liquid non-occlusion states correspond to different emptying mechanisms dominated by the gravity effect and the ‘wedge’ effect, respectively. Existence of the re-entrant transition is accompanied by occurrence of unconditional liquid non-occlusion at large enough or small enough contact angles regardless of Bond numbers. The critical Bond numbers at a contact angle γ for vertical upward eccentricity are equal to those at a contact angle 180° − γ for vertical downward eccentricity. In a parameter space (γ, e/(1 − χ)), the region with the re-entrant transition becomes larger with the eccentric angle varying from 0° (horizontal) to 90° (vertical). Optimization of geometrical parameters and inner and outer contact angles can lead to better effect of capillary emptying. This paper provides a very effective scheme for removing a liquid blockage from a capillary in optofluidics/microfluidics.

Statistical characterization of liquid film fluctuations during gas-liquid two-phase counter-current flow in a 1/30 scaled-down test facility of a pressurized water reactor (PWR) hot leg

The present work investigates the statistical characteristics of the fluctuations of the liquid film thickness obtained by resistive-conductance probe signals of a complex geometry representing a 1/30 down-scaled of a PWR hot leg. Here, four locations at the horizontal part of the test section were assessed, while the flow development was investigated through a close observation by using a high-speed video camera. Next, the normalized voltages, indicating the liquid film thickness fluctuations, are shown in the time-series. From the fluctuations, the amplitudes representing the film thickness were recorded. Hence, such statistical diagnostic tools were applied on the basis of time-domain, frequency-domain and also time–frequency domain analyses. From the probability density function, the distributions of the fluctuations were assessed, whereas the power spectral density function describes the dominant frequencies. In addition, the Kolmogorov entropy denotes the chaotic level of the signal, meanwhile the wavelet energy corresponds to several details on the wavy interfaces on the basis of its frequency scales. Next, those parameters were statistically employed to elaborate the interfacial behaviors due to the signal characteristics. The results indicate that the low dominant frequency corresponds to the occurrence of either liquid blockage or slugs during the acquisition, meanwhile the largest scale fluctuations reveal the wave movements.

An overview on the enhanced gas condensate recovery with novel and green methods.

A consideration of the negative environmental aspects of fossil fuels has made natural gas the best choice to meet the human demand for energy. The condensate gas reservoir is one source of gases that tolerates skin problems (liquid blockage). Conventional methods for inhibiting or removing liquid blockages are momentary treatments, non-eco-friendly, and expensive. Therefore, new methods have been introduced, such as wettability alteration toward liquid repellency, renewable energies, thermochemical reactions and waves for heating reservoirs, and CO2 injection. This paper reviews the methods for altering the wettability of porous media by fluorochemicals, fluorinated nanoparticles (NPs), and free fluorocarbon materials from natural substances. NPs, particularly silicon-based types, as a green, clean, and emerging technology that are more compatible with the environment, were investigated for their ability to alter the wettability and upgrade conventional materials, such as polymers and surfactants. The feasibility of using renewable energies, thermochemical reactions, and waves for heating the gas condensate reservoir to overcome the skin problem and return the reservoir to the reasonable and economical gas production is reviewed. Finally, CO2 injection is introduced as a multi-purpose green method to enhance gas condensate recovery and allow CO2 sequestration.

Visualization of two-phase refrigerant flow in the inlet header of brazed plate heat exchangers and its effect on distribution

• Two-phase flow visualization is achieved by a clear window on the inlet header. • Flow regime in the inlet header is periodic and one cycle has two or three stages. • Flow regime in the inlet header significantly affects the two-phase distribution. • Effects of mass flux, inlet vapor quality, and the number of plates are examined. This paper presents an experimental study of two-phase R134a flow in the inlet header of brazed plate heat exchangers and its effect on flow distribution among the channels. Visualization of the two-phase flow is accomplished through a 3-D printed transparent window on the inlet header of the heat exchangers. The two-phase flow distribution among channels is quantified based on infrared images of the heat exchanger sidewalls. At the test conditions, the observed flow regimes in the inlet header are periodic and two or three stages are identified in one cycle: top corner vapor flow, vapor jet flow, and (conditional) liquid blockage flow. Among them, the top corner vapor flow affects the distribution most, in which the vapor refrigerant is mainly present at the top corner of the header and branches out through the first several channels, leaving the liquid refrigerant to occupy the rest flow area of the inlet header and present a single-phase like distribution profile. When the inlet vapor quality increases, the distribution of the liquid refrigerant is improved since the vapor refrigerant can reach more downstream channels to help balance the total pressure drop. With the mass flux increases, the maldistribution caused by the header induced pressure drop is more significant, which compromises the benefit brought by the higher vapor momentum. When the number of plates is increased, the liquid refrigerant distribution is worse due to an increased pressure drop in the headers.

Flow regime transition and liquid distribution in a 3D concurrent downflow three-phase moving bed

Based on a cold-flow experimental setup, the transition between trickle flow and pulse flow in a 3D concurrent downflow three-phase moving bed is investigated by the standard deviation of pressure drop and visual observations. Results show that at a constant gas flow rate, the trickle-to-pulse transition shifts to a higher liquid flow rate with the increasing solid flow rate because the particle moving inhibits the formation of local liquid blockage. Furthermore, an empirical model is proposed to fit the trickle-to-pulse transition boundary by correlating the dynamic liquid holdup at the boundary with the gas Reynolds number, the particle velocity, and the relative viscosity. Finally, the effects of the particle moving on the liquid distribution are investigated, which shows that the particle moving makes the liquid distribution more uniform when the solid flow rate is smaller than a certain value. But further increasing the solid flow rate, the liquid distribution becomes uneven.

Liquid blockage and flow maldistribution of two-phase flow in two parallel thin micro-channels

In this study, flow maldistribution in a system of two parallel thin micro-channels with shared inlet and outlet manifolds is experimentally investigated with one channel subject to single-phase flow and the other to two-phase one. The flow pattern, pressure drop, gas flow rate in the single-phase flow channel Q1 and two-phase flow channel Q2 are studied. Film flow patterns are observed for all the cases of the study, consistent with literature work. The Q2Q1 ratio is defined as a direct measure to flow maldistribution. Theoretical derivation shows that Q2Q1 is inverse of the two-phase multiplier ϕ or Q2Q1=1ϕ. Three levels of liquid flow rate are examined and presented to show three representative trends: (1) For the highest water flow rate, i.e. 10−2 m/s, Q2Q1 is found to monotonically increase with the air flow rate, with its value Q2Q1 as low as about 0.2 at 0.86 m/s gas velocity and approaching 0.65 at 3.44 m/s. (2) For the lowest water velocity, i.e. 10-4 m/s, Q2Q1 shows decrease at first, followed by an increase, as the superficial gas velocity increases from 0.86 m/s to 3.44 m/s. It reaches about 0.76 at 0.86 m/s gas velocity and drops to about 0.55 at 1.72 m/s. (3) For the intermediate water velocity, i.e. 10-3 m/s, two “steady” states are identified at 0.86 m/s gas velocity with one having Q2Q1 as high as about 0.69 and the other about 0.52. The rest follows a similar trend as 10-4 m/s liquid velocity. The observed two “steady” states and changing trend at the two low liquid velocities may be due to the altered liquid blockage near the channel exit. It is also indicated that the two-phase multiplier ϕ obtained in single channel testing may not be used to measure flow maldistribution in multiple-channel systems. The work is important to study of two-phase flow, multi-channel design, flow maldistribution, and flow control in micro-channels for PEM fuel cells, electrolyzers, and thermal devices.

Simulation of solvent treatments for fluid blockage removal in tight formations using coupled three-phase flash and capillary pressure models

Water and condensate blockage near production wells in unconventional reservoirs can significantly reduce oil and gas production rates. This paper presents a new approach for more accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. A cubic equation of state is used to model mixtures of solvent, hydrocarbons and water that form up to three phases. The three-phase flash model is coupled with a three-phase capillary pressure model to account for the effect of capillary pressure in confined space. The capillary pressure function includes the impact of several important petrophysical properties such as pore size distribution and wettability. A compositional simulator is used to demonstrate the importance of the new phase behavior model. Single- and multi-cycle processes of methanol, dimethyl ether or CO2 injection are simulated to remove liquid blockage and increase production rate in tight oil/gas reservoirs. Simulation results show that DME is more efficient than methanol and CO2 for removal of liquid blockage in tight oil/gas reservoirs because DME is miscible with both oil and water under the simulated reservoir conditions.

Subsurface Compression Lifts Liquids, Increases Gas Production in Unconventional Well Trial

It is well known that liquid loading in unconventional gas wells can dramatically reduce production and lead to premature abandonment. Liquid loading creates a “vicious cycle” that occurs when liquid blockage creates backpressure in the wellbore or pore space in the formation, resulting in reduced gas velocity and leading to more liquid accumulation over time. Electrical submersible pumps (ESPs) and other artificial lift technologies are typically unable to remove liquids in both the vertical and horizontal sections of the well. A new downhole compressor solution, based on advanced magnetic technologies, was developed by Upwing Energy and recently completed its first field trials in an unconventional gas well operated by Riverside Petroleum. Analysis of results during the trial revealed a 62% increase in gas production and significant increase in liquid production over its steady­state performance using a rod pump prior to the subsurface compressor system (SCS) installation. Subsurface Compressor System The SCS is designed to provide reliable performance in the downhole environment by eliminating the common points of failure in conventional ESPs. It is based on proven magnetic technologies used in topside and subsea oil and gas applications (Fig. 1), which were deployed downhole successfully for the first time during the Riverside trial, including: A high­speed permanent magnet (PM) motor A shaftless magnetic coupling between the motor and compressor Passive noncontact magnetic bearings with electronic dampers A sensorless wide­frequency variable speed drive at the surface controls the motor at speeds up to 50,000 rpm via a long stepout. The hybrid axial wet­gas compressor is driven by the hermetically sealed high­speed PM motor. Torque is conveyed from the motor to the compressor with no mechanical shaft or seals, eliminating the need for a motor protector to isolate the motor from downhole fluids. This “protector­less” architecture eliminates a frequent source of vulnerability for conventional downhole artificial lift systems. The SCS lowers the bottomhole well pressure, increasing the velocity of the gas stream, removing liquids from the vertical and horizontal sections of the well, and preventing vapor condensation by increasing the temperature of the gas when exiting the compressor. Decreased backpressure from liquid loading results in increased gas production, which in turn accelerates liquid unloading. Once the liquid is carried by the gas stream, the lower pressure at the compressor intake and the higher temperature at the compressor discharge prevents vapor condensation and enhances the carryover of liquids to the surface by the gas stream. Field Trial The SCS was deployed in an unconventional shale gas well owned by Riverside Petroleum in Indiana. The trial period started at the end of October 2019, and the SCS was removed in early December. The well has a 2,000-ft vertical wellbore and a 5,000-ft horizontal wellbore, where liquid had accumulated (Fig. 2). The compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1,000 ft into the horizontal section to provide sufficient velocity to carry liquids while minimizing friction losses. A shroud was used to be able to carry the extended length of the tail pipe.

Experimental investigation of wettability alteration of carbonate gas-condensate reservoirs from oil-wetting to gas-wetting using Fe3O4 nanoparticles coated with Poly (vinyl alcohol), (PVA) or Hydroxyapatite (HAp)

Wettability alteration near-wellbore region in a gas-condensate reservoir is an effective way to reduce liquid blockage. To this end, Fe3O4 NPs (nanoparticles) first synthesized by the co-precipitation method and then coated with Poly (vinyl alcohol) (PVA) and or Hydroxyapatite (HAp). Besides, the synthesized NPs and two core-shell nanostructures were characterized by the Field Emission Scanning Electron Microscopy (FE-SEM), X-ray diffraction (XRD) analysis and the Fourier-Transform Infrared spectroscopy (FTIR). The synthesized NPs coated with PVA and or HAp were then exploited to coat on the surface of carbonate rocks by the dip-coating method in the course of 48 h. Next, the contact angle on the surface of carbonate rocks in condensate/air and water/air systems was measured in a wide range of pressure from 1 to 40 bar. In contact angle measurements, the effect of different parameters including the NPs concentration, temperature and pressure was examined.Also, the spontaneous imbibition and fluid flow tests were fulfilled in the artificial core-plugs before and after the wettability alteration. The results show that the imbibition rate of water and condensate noticeably reduced after the wettability alteration by both core-shell nanostructures. Additionally, the pressure drop and breakthrough time significantly diminished after the wettability alteration by both core-shell nanostructures. Moreover, coating of the two core-shell nanostructures on the surface of carbonate rocks was confirmed by the Scanning Electron Microscope (SEM) analyses.Furthermore, based on contact angle measurements between gas-condensate and the carbonate artificial core-plug surface after the treatment with the Fe3O4-PVA and or Fe3O4-HAp nanostructures, the optimum concentrations of Fe3O4/PVA and Fe3O4-HAp nanostructures in distilled water were 0.5 wt % and 0.4 wt %, respectively, to attain the greatest wettability alteration from oil-wetting to preferentially gas-wetting. In this condition, the contact angle between gas-condensate and the treated carbonate artificial core-plug surface by the Fe3O4/PVA and or Fe3O4-HAp nanostructures shifted from 10 ͦ to 66 ͦ and or 90 ͦ, respectively. Also, the contact angle between water and the treated carbonate artificial core-plug surface using the Fe3O4/PVA and or Fe3O4-HAp NPs altered from 62 ͦ to 107 ͦ and or 116 ͦ, respectively.Generally, the iron oxide NPs coated with HAp significantly improved the wettability of the rock samples from oil-wetting to gas-wetting as compared to those coated with PVA.Finally, the spontaneous imbibition experiments were carried out in the tight rock before and after the wettability alteration. Results demonstrated that the imbibition rate of gas-condensate decreased about 63 and 64% after the wettability alteration by the Fe3O4-PVA/DW and Fe3O4-HAp/DW nanofluids with the optimum concentration of 0.5 and 0.4 wt %, in sequence. Additionally, experimental results of the fluid flow tests at high pressures showed that the pressure drop reduced 34 and 32% after the wettability alteration for both Fe3O4-PVA/DW and Fe3O4-HAp/DW nanofluids, respectively.

Coupled Capillary-Pressure and Three-Phase Flash Models Simulate Liquid Blockage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190242, “Simulation of Water and Condensate Blockage and Solvent Treatments in Tight Formations Using Coupled Three-Phase Flash and Capillary-Pressure Models,” by Sajjad S. Neshat, SPE, Ryosuke Okuno, SPE, and Gary A. Pope, SPE, The University of Texas at Austin, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Water and condensate blockage near production wells in unconventional reservoirs can reduce oil- and gas-production rates significantly. This paper presents a new approach for more-accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. Introduction In this paper, coupled three-phase flash and capillary-pressure models are presented for simulation of tight oil and gas reservoirs. The capillary pressure between each phase pair (e.g., oil/gas or oil/aqueous) is calculated with a general three-phase capillary-pressure model that integrates the effect of important petrophysical properties including pore-size distribution, phase saturations, and different wettability conditions. The capillary-pressure function is integrated with three-phase flash calculations to define the equilibrium state between oil, gas, and aqueous phases under reservoir conditions. The criterion for selection of cubic equation-of-state (EOS) roots is extended for three-phase mixtures. This method minimizes the global Gibbs free energy (GFE) of the whole mixture instead of minimizing the free energy of each phase separately. The models are then used for simulation of primary production and solvent enhanced-oil-recovery (EOR) processes in tight formations. Using rock and fluid properties for tight oil and gas reservoirs, the effect of water and condensate blockage and capillary pressure on production is simulated. The use of solvents to remove liquid blockage and to increase production rates is extended to tight formations with high capillary pressure. Coupled Three-Phase Flash and Capillary-Pressure Models At three-phase equilibrium conditions, the chemical potential of each component must be equal in all three phases. In the presence of capillary pressure, the chemical potentials are calculated at corresponding phase pressures. Capillary pressure across a two-phase interface is a function of the surface curvature and interfacial tension (IFT). The variation in pore size and interfacial curvature can be accounted for by saturation-dependent functions. In the presence of a third phase, the interface between any two phase pairs would shift toward either larger or smaller pores depending on wettability conditions. A general three-phase model that can be used to define the capillary pressure between any phase pairs under the entire range of wettability conditions has been coupled with a three-phase relative permeability model with three-phase hysteresis and compositional consistency and was validated through measured three-phase relative permeability data. For the applications discussed in this study, it is assumed that the gas phase is always the most nonwetting phase, while a mixed wetting condition for oil and aqueous phases is assumed.

Interfacial behavior of the air-water counter-current two-phase flow in a 1/30 scale-down of pressurized water reactor (PWR) hot leg

The study on the interfacial phenomena of flooding during the counter-current flow of gas-liquid in a complex pipe was carried-out experimentally. It consists of a combination of the horizontal pipe, elbow and inclined pipes to simulate the hot leg pipe in a PWR. The inner diameter was 25.4 mm as scale down of real hot leg pipe of German Konvoi type reactor. The visual observations were performed using high-speed video cameras. The measured parameters were the liquid film thickness and the pressure difference between reactor pressure vessel (RPV) simulator and steam generator (SG) simulator. The film thickness inside the test pipe was determined by using the processed image of visual data.As a result, three different mechanisms at the onset of flooding in counter-current were clarified, and are strongly affected by liquid superficial velocity. At low liquid superficial velocity (JL), the flooding mechanism is triggered by the presence of wavy interface along the horizontal pipes in the form of a liquid blockage on the elbow. At the medium JL, the slug was detected along the horizontal pipe. However, the slug collapses immediately since the water is insufficient to maintain the blockage. At high JL, the slug occurs and travels along the horizontal pipe until the elbow. Moreover, the effect of the length of horizontal pipe on the interfacial behavior of air water counter current flow also can be explained. As the length of the horizontal pipe decreases, the onset of flooding occurs at a higher gas liquid mass flow rate.

The effect of boundary conditions and droplet entrainment on severe slugging using a Lagrangian slug tracking model

This study presents a Lagrangian slug tracking model for prediction of slug flow in multiphase flow pipelines. Simulations are compared with severe slugging experiments from the SINTEF Large Scale Multiphase Laboratory with 0.189m inner diameter and a length of about 1000m. The fluids used in the experiments are nitrogen and naphtha, and the system pressure is 25bar. The model is shown to give fast and accurate results within the experimental accuracy without the need for a sub-grid model, as long as the grid size is not too large around the riser bottom where the liquid blockage occurs. It is also shown that simulations using a constant pressure boundary condition at the outlet are not always adequate, as the pressure fluctuations in the receiving facilities can significantly affect the flow. Furthermore, we show that the inclusion of a droplet field has a significant impact on the predicted slugging periods.

Practical insights into liquid loading within hydraulic fractures and potential unconventional gas reservoir optimization strategies

The U.S. has experienced a resurgence of the upstream hydrocarbon sector in recent years, owing to the economic extraction of oil and gas from ultra-tight reservoirs using multistage hydraulic fracturing in horizontal wells. This success is often attributed to slick-water stimulation treatments that help create extensive complexity and contact with the low permeability reservoir. In this process, hundreds of thousands of barrels of water are pumped downhole, along with friction reducers, low concentration linear gel, fracture propping sand and other additives, to create and sustain these fractures. However, only a small percentage of this stimulation water is recovered back once the well is put back on production. This not only leads to excessive water hauling costs for operators in each consecutive well but also liquid blockage for hydrocarbon flow. Such water blockage/loading may become a serious concern in dry gas reservoirs such as the Marcellus field in the northeastern U.S., due to the unfavorable hydrocarbon mobility ratios. In spite of its implications on early and late time well performance, the issue of hydraulic fracture cleanup and gas flowback through it when drained through a horizontal wellbore is still an insufficiently understood subject. In this study the authors investigate the potential of liquid loading (stimulation water or condensate) within the hydraulic fracture itself due to low matrix permeability and insufficient drawdown conditions. Similar conditions may also arise late in the life of well when the reservoir pressure has declined significantly or due to wellbore design issues. A 3D reservoir simulation model with a discrete, planar hydraulic fracture is set up to investigate the competition between capillary, viscous and gravity forces within the fracture. The results indicate a strong tendency for liquid loading in the ultra-low permeability gas reservoirs under common operational constraints and offer recommendations on best practices to minimize its impact.

Modeling criteria for extraction regime transitions for microscale in-situ vapor extraction applications

A major detriment of two-phase microscale flow systems is a significantly large pressure drop. For flow boiling the potential for flow instabilities is also a major concern. Both disadvantages may be suppressed by extracting vapor through a hydrophobic porous wall of the channel as a means to reduce the channel vapor fraction. The vapor extraction may occur as different regimes either as evaporation, bubble extraction or a combination of both. In the design of vapor extraction systems, it is important to accurately predict extraction rates, different extraction regimes, and the effect of extraction on the heat transfer and channel flow conditions. This study focuses on two parts: the development of physic-based models for the transition criteria among (i) the extraction mechanism regimes, and (ii) the extraction flow regimes for microscale flow boiling. The identification and conditions for the various extraction regimes are discussed and criteria for transition are developed based on physical concepts. Six potential extraction mechanism regimes are identified: (a) no extraction, (b) evaporation, (c) bubble extraction, (d) bubble extraction with partial liquid blockage, (e) bubble extraction with evaporation, and (f) liquid breakthrough. Based on the criteria for the extraction mechanism regimes, the rate of vapor extraction is modeled and used to analyze the effects of vapor extraction on the dynamics of two-phase flow boiling. The results show six extraction flow regimes for two-phase flow boiling: (i) single-phase evaporation, (ii) two-phase evaporation – bubble collapse, (iii) full extraction – stable, (iv) full extraction – unstable, (v) partial extraction – stable and (iv) partial extraction – unstable.

Wettability alteration to intermediate gas-wetting in low-permeability gas-condensate reservoirs

Gas-condensate reservoirs experience significant productivity losses as reservoir pressure drops below the dew point due to condensate accumulation and water blocking and the subsequent reduction in gas relative permeability. One potential way to overcome this problem is to alter reservoir wettability to gas-wetting to reduce condensate accumulation and water blocking in the near wellbore and maintain high productivity. The major goal of this work was to study the mobility of the gas and liquid phase (both water and oil) before and after wettability alteration from strong liquid-wetting to intermediate gas-wetting. For this purpose, in addition to relative permeability measurements, we also conducted various other tests to demonstrate that liquid mobility can be improved significantly due to wettability alteration. As wettability modifiers, fluorinated polymers are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockage under high temperature. The contact angle analyses, capillary rise, flow tests, and imbibition spontaneous tests were used to estimate the effect of treatments on wettability. Experimental results demonstrated that the fluorinated polymers can alter the wettability of cores from strong liquid-wetting to gas-wetting, which could decrease the amount of water invaded and resided in the gas formation. Core flood test results demonstrated that the relative permeabilities of both the gas and the liquid phases were increased significantly after the wettability alteration to preferential gas-wetness. The residual liquid saturation was decreased, and the gas production was enhanced greatly due to the wettability alteration. These results imply that gas well deliverability may increase substantially when wettability is altered to intermediate gas-wetting. Efficiency in the extraction of natural gas is important to improve the productivity of gas-condensate reservoirs where liquid accumulates, which is beneficial for the economic and environmental considerations of the oil and gas industry.

Alteration of Porous Media Wettability to Gas-Wetting by Sol-Gel and Fluorochemical Surfactant

Gas well productivity is affected by liquid blockage of the wellbore region, and if the wettability of porous media shifts to gas-wetting, then deliverability in gas condensate reservoirs will increase. In this article, a sol-gel process and modification of perfluoroalkyl methacrylic copolymer (Zonyl 8740) were employed to alter the wettability of rock core surfaces. Contact angle analysis and a spontaneous imbibition test suggested that wettability of the core could be altered to gas-wetting by sol-gel deposition and treatment with Zonyl 8740. Consequently, the rough surfaces made by sol-gel, which were modified by Zonyl 8740, resulted in wettability reversal to gas-wetting of porous media.

Methanol treatment in gas condensate reservoirs: A modeling and experimental study

Well productivity in gas condensate reservoirs is reduced by condensate blockage when the bottom-hole pressure drops below dew point pressure. The present experimental study on limestone cores shows that the relative permeability of gas decreases due to liquid blockage; furthermore, methanol has proven effective in the removal of condensate and restoration of gas relative permeability. In this research, the decrease in gas relative permeability caused by condensate banking and the effect of methanol treatment on condensate-blocked rocks was simulated using the cubic-plus-association (CPA) equation of state. The CPA equation of state was applied to the modeling of two-phase flows through cores for methanol–hydrocarbon mixtures due to charge transfer and hydrogen bonding, both of which may strongly affect the thermodynamic properties of such mixtures. Differential equations were solved by means of the orthogonal collocation method, a method particularly attractive for solving nonlinear problems. The modeling results confirm the experimental results, and both methods indicate that significant productivity loss can occur in retrograde gas condensate reservoirs when the flowing bottom-hole pressure falls below dew point pressure. Moreover, the results show that methanol treatment can improve gas relative permeability by a factor of about 1.3–1.6. These results may help reservoir engineers and specialists to restore the lost productivity of gas condensate.

Liquid Loading and Gas Well Deliverability: The Production Approach

The authors consider the concept of liquid blockage in a gas wellbore and how it can be prevented by adequately predicting the fluid mixtures' (gas, oil, water and condensates) behavior as it travels along the wellbore to the surface using the IPM packages MBAL, PROSPER, and GAP to model the flowrate and tubing size performance. The central objective of the modeling work was to determine the best tubing size needed for optimum delivery of the gas well in focus. The results from the analysis show 0.1397 m (5.500″) tubing as the best size for flowing the gas well.