Mitigation of Gas Condensate Banking Using Thermochemical Fluids and Gemini Surfactant: A Comparison Study

2021 ◽  
Author(s):  
Amjed Hassan ◽  
Mohamed Mahmoud ◽  
Muhammad Shahzad Kamal ◽  
Abdulaziz Al-Majed ◽  
Ayman Al-Nakhli ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Gemini Surfactant ◽  
Integrated Approach ◽  
Capillary Forces ◽  
Gas Production ◽  
Wettability Alteration ◽  
Comparison Study ◽  
Multiple Fractures

Abstract Accumulation of condensate liquid around the production well can cause a significant reduction in gas production. Several methods are used to mitigate the condensate bank and maintain the gas production. The most effective approaches are altering the rock wettability or inducing multiple fractures around the wellbore. This paper presents a comparison study for two effective approaches in mitigating the condensate bank. The performance of thermochemical fluids (TCF) and gemini surfactant (GS) in removing the condensate liquid and improve the formation productivity is studied. In this work, several experiments were carried out including coreflooding, capillary pressure, and relative permeability measurements. The profiles of condensate saturations show that GS can mitigate the condensate bank by 84%, while TCF removed around 63% of the condensate liquid. Also, GS and TCF treatments can increase the relative permeability to condensate liquid by factors of 1.89 and 1.22 respectively, due to the wettability alteration mechanism. Capillary pressure calculations show that GS can reduce the capillary pressure by around 40% on average, while TCF leads to a 70% reduction in the capillary forces. Overall, injection of GS into the condensate region can lead to changing the wettability condition due to the chemical adsorption of GS on the pore surface, and thereby reduce the capillary forces and improve the condensate mobility. On the other hand, TCF injection can improve rock permeability and reduce capillary pressure. Both treatments (GS and TCF) showed very attractive performance in mitigating the condensate bank and improving the formation production for the long term. Finally, an integrated approach is presented that can mitigate the condensate damage by around 95%, utilizing the effective mechanisms of GS and TCF chemicals.

Mitigation of Gas Condensate Banking Using an Integrated Chemical Approach

2021 ◽  
Author(s):  
Amjed Mohammed Hassan ◽  
Mohamed Ahmed Mahmoud ◽  
Ayman Raja Al-Nakhli
Keyword(s):  
Zeta Potential ◽  
Hydraulic Fracturing ◽  
Thermochemical Treatment ◽  
Chelating Agent ◽  
Integrated Approach ◽  
Gas Production ◽  
Wettability Alteration ◽  
Gas Reservoirs ◽  
Multiple Fractures ◽  
Well Production

Abstract In gas reservoirs, the well production can be reduced due to the development and accumulation of condensate in the near-wellbore zone. Various techniques are used to minimize the condensate damage and maintain hydrocarbon production. Hydraulic fracturing and wettability alteration techniques are the most effective methods. However, these techniques are expensive, especially in deep gas reservoirs. This paper introduces a new approach for mitigating condensate accumulation by integrating the hydraulic fracturing and wettability alteration treatments. The efficiency of two chemicals that can generate multiple fractures and alter the fracture surfaces to less condensate status is investigated in this work. Thermochemical fluids and chelating agent solutions are used to mitigate the condensate damage and improve gas production for the long term. Several laboratory measurements were carried out to study the performance of the proposed approach; coreflooding, zeta potential, and nuclear magnetic resonance (NMR) experiments were conducted. The chemicals were injected into the tight rocks to recover the condensate and improve the flow conductivity. Zeta potential was performed to assess the rock wettability before and after the chemical injection. Moreover, the changes in pores network due to the chemical treatments as analyzed using the NMR technique. Thermochemical treatment removed around 66% of the condensate liquid, while the chelating agent reduced the condensate saturation by around 80%. The main mechanism for condensate removal during thermochemical flooding is the generation of micro-fractures that increase the rock permeability and improve the condensate flow. On the other hand, chelating agents can alter the rock wettability toward less oil-state, leading to considerable recovery of the condensate liquid utilizing a wettability alteration mechanism. Finally, an integrated approach is suggested to injecting thermochemical fluids followed by chelating agent solutions. The proposed technique can lead to generating micro-fractures of less oil-wet surfaces, consequently, the condensate bank can be removed by more than 90%.

Displacement Studies in Dolomite With Wettability Control by Octanoic Acid

1973 ◽  
Vol 13 (04) ◽  
pp. 221-232 ◽  
Author(s):  
N.R. Morrow ◽  
P.J. Cram ◽  
F.G. McCaffery
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Significant Influence ◽  
Octanoic Acid ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Relative Permeability Curves

Abstract Various nitrogen-, oxygen- and sulfur-containing compounds native to crude oils were screened for their effect on wettability as measured by contact angle. Solid substrates of quartz, calcite, and dolomite crystals were used to represent reservoir rock surfaces. With water and decane as liquids, contact angles were measured after a given polar compound was added to the oil phase. Contact angles measured at the two types of carbonate surfaces were generally similar. None of the nitrogen or sulfur compounds studied gave contact angles greater than 66 degrees on either quartz or carbonates. Of the oxygen-containing compounds, octanoic acid gave the widest range of contact angle - 0 degrees to 145 degrees on dolomite - over a molar concentration range up to 0.1. Capillary - pressure and relative-permeability curves were obtained for water and solutions of octanoic acid in oil, using packings of powdered dolomite as the porous medium. Because of a slow reaction between dolomite and octanoic acid, which was not revealed by standard contact angle studies, special precautions were needed to ensure satisfactory wettability control during displacement tests. Capillary-pressure drainage curves were measured at six contact angles, ranging from 0 degrees to 140 degrees. Drainage-imbibition cycles for three packings of distinctly different particle size were measured at contact angles of 0 degrees and 49 degrees. The effect of contact angle on imbibition capillary pressures was close to that found previously for porous polytetra-fluoroethylene, whereas there was comparatively polytetra-fluoroethylene, whereas there was comparatively less effect on drainage behavior-steady-state relative permeability curves exhibited distinct differences for contact angles of 15 degrees, 100 degrees and 155 degrees. Introduction Waterflooding is the most successful and widely applied improved recovery technique. Its application in Alberta has, on the average, more than doubled the recovery obtained by primary depletion. However, even after waterflooding, it is estimated that two-thirds of the discovered oil remains unrecovered. Interfacial forces acting during waterflooding lead to the entrapment of large quantities of residual oil in the swept zones. Considerable attention has been paid to recovering this oil through new recovery methods in which the interface is eliminated as in miscible processes, or the interfacial tension is drastically lowered, as in surfactant floods. Such processes involve a high initial cost for an injected solvent or surfactant bank. Recently released information on a variety of such improved recovery techniques has not been altogether encouraging with regard to developing economical processes. A distinct alternative to eliminating the interface is to understand it and learn how it can be manipulated to give increased waterflood recoveries. A prospect for improved recovery at interfacial tensions of the order normally encountered in reservoirs lies in a favorable adjustment of wettability by incorporating small amounts of low-cost additives in the floodwater. A first step in developing the technology of improved recovery by wettability alteration is to determine the effect of wettability alteration on displacement in systems of uniform wettability. It has been shown that, even in the "near miscible" surfactant processes, wettability can still have a significant influence on the extent to which interfacial tension must be lowered in order to mobilize residual oil. At the time when waterflooding first found widespread use, wettability was recognized as a variable that might well have a significant influence on recovery performance. Reservoir wettability and the role of wettability in displacement has been the subject of some 50 or so publications. Even so, many aspects of wettability are not well understood and there is no general agreement on a satisfactory method of characterizing it. Opinions as to the optimum wettability condition for recovery cover the spectrum from strongly water-wet through weakly water-wet or intermediately wet to strongly oil-wet. It has recently been suggested that a mixed wettability condition can give high ultimate recoveries. SPEJ P. 221

scholarly journals Wettability Effects on Capillary Pressure, Relative Permeability, and Irredcucible Saturation Using Porous Plate

2014 ◽  
Vol 2014 ◽  
pp. 1-12 ◽  
Author(s):  
Olugbenga Falode ◽  
Edo Manuel
Keyword(s):  
Porous Media ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Porous Plate ◽  
Reservoir Rock ◽  
Flow In Porous Media ◽  
Wettability Alteration ◽  
Initial Water ◽  
Phase Saturation

An understanding of the mechanisms by which oil is displaced from porous media requires the knowledge of the role of wettability and capillary forces in the displacement process. The determination of representative capillary pressure (Pc) data and wettability index of a reservoir rock is needed for the prediction of the fluids distribution in the reservoir: the initial water saturation and the volume of reserves. This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure, relative permeability, and irreducible saturation. Initial water-wet reservoir core samples with porosities ranging from 23 to 33%, absolute air permeability of 50 to 233 md, and initial brine saturation of 63 to 87% were first tested as water-wet samples under air-brine system. This yielded irreducible wetting phase saturation of 19 to 21%. The samples were later tested after modifying their wettability to oil-wet using a surfactant obtained from glycerophtalic paint; and the results yielded irreducible wetting phase saturation of 25 to 34%. From the results of these experiments, changing the wettability of the samples to oil-wet improved the recovery of the wetting phase.

Interpreting Relative Permeability and Wettability From Unsteady-State Displacement Measurements

1981 ◽  
Vol 21 (03) ◽  
pp. 296-308 ◽  
Author(s):  
J.P. Batycky ◽  
F.G. McCaffery ◽  
P.K. Hodgins ◽  
D.B. Fisher
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Capillary Forces ◽  
Unsteady State ◽  
The Core ◽  
Fluid Systems ◽  
System Length ◽  
Capillary Pressure Gradient

Abstract A procedure has been developed and tested for evaluating the capillary pressure and wetting properties of rock/fluid systems from unsteady-state displacement data such as that used for calculating two-phase relative permeability characteristics. Currently, the common practice is to conduct most coreflooding experiments so that the capillary pressure gradient in the direction of flow is small compared with the imposed pressure gradient. The proposed method, on the other hand, is based on performing low rate displacements during which capillary forces and, hence, end effects can influence the saturation distribution and pressure response of the core sample. Besides providing a means for monitoring capillary forces and wettability during the dynamic displacement test, the proposed method has the advantage of permitting the displacement tests to be conducted at rates more typical of those in the reservoir. Thus, it is possible to avoid potential problems such as fines migration and emulsion formation, and the method permits a realistic representation of transient interfacial effects that can be important with reservoir fluid systems and chemical flooding agents. Specifically, the method involves performing low rate displacements between the irreducible-water and residual-oil endpoint saturations. Except for the added provision of stopping, restarting, and sometimes reversing the flow after the endpoints have been reached, these are routine unsteady-state displacements in which the standard pressure drop is measured external to the core between the inlet and outlet fluid streams. The dynamically measured capillary pressure properties—besides indicating strong, weak, intermediate, or mixed wettability—then can be used to derive relative permeabilities from the displacement data. Examples of the technique for determining wettability are given for pure-fluids/Berea-sandstone andreservoir-fluids/preserved-reservoir-rock systems. Introduction It long has been recognized that capillary forces can influence the results of relative permeability and oil recovery measurements on core samples.1–5 A scaling criterion for linear displacement tests has been proposed to remove the dependence of oil recovery on displacement rate and system length.5 The objective is to avoid appreciable influence of capillary forces on the flooding behavior that causes a spreading of the displacement front and the well-known end effect or buildup of the wetting phase at the ends of the core. The suggested scaling causes the capillary pressure gradient in the direction of flow to be small compared with the imposed pressure gradient and is expressed asEquation 1 where L is system length (in centimeters), µ is displacing phase viscosity (in centipoise or millipascal-seconds), and q/A is flow rate per unit cross-sectional area (in centimeters per minute). Bentsen6 refined the criterion for neglecting capillary forces to include consideration of the mobility ratio. In related work, Peters and Flock7 recently proposed a dimensionless number and its critical value for predicting the onset of instabilities resulting from viscous fingering at unfavorable mobility ratios. In apparent contrast to the scaling coefficient suggested in Eq. 1, displacements were shown to decline at high flow rates for a given core system and wettability condition.

Capillary Pressure Effects on Estimating the Enhanced-Oil-Recovery Potential During Low-Salinity and Smart Waterflooding

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 481-496 ◽  
Author(s):  
Pål Østebø Andersen
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Smart Water ◽  
Relative Permeability Curves

Summary Many experimental studies have investigated smart water and low-salinity waterflooding and observed significant incremental oil recovery after changes in the injected-brine composition. The common approach to model such enhanced-oil-recovery (EOR) mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness can retain much oil at the outlet of the flooded core because of the capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in highly permeable cores at typical laboratory rates. Injecting a brine that changes the wetting state to less-oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation. This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing coreflooding that accounts for wettability changes caused by changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability-alteration (WA) component coupled to the shifting of relative permeability curves and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically because of the changing of one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and the magnitude of capillary end effects can be reduced because of increased water-wetness or because of a reduction in water relative permeability giving a greater viscous drag on the oil.

Interrelationship of Temperature and Wettability on the Relative Permeability of Heavy Oil in Diatomaceous Rocks (includes associated discussion and reply)

2006 ◽  
Vol 9 (03) ◽  
pp. 239-250 ◽  
Author(s):  
Josephina M. Schembre ◽  
Guo-Qing Tang ◽  
Anthony R. Kovscek
Keyword(s):  
Elevated Temperature ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Heavy Oil ◽  
Thermal Recovery ◽  
Wettability Alteration ◽  
Effect Of Temperature ◽  
Phase Saturation ◽  
Effects Of Temperature ◽  
Relative Permeability Curves

Summary The evaluation of thermal-recovery processes requires relative permeability functions, as well as information about the effects of temperature on these functions. There are significant challenges encountered when estimating relative permeability from laboratory data, such as the accuracy of measurements and generalized assumptions in the interpretation techniques. A novel method is used here to estimate relative permeability and capillary pressure from in-situ aqueous-phase saturation profiles obtained from X-ray computerized tomography (CT) scanning during high-temperature imbibition experiments. Relative permeability and capillary pressure functions are interpreted simultaneously, including possible nonequilibrium effects. Results obtained show a systematic shift toward increased water-wettability with increasing temperature for diatomite reservoir core. The measured changes in relative permeability are linked to the effect of temperature on the adhesion of oil-coated fines to rock surfaces and, ultimately, to rock/fluid interactions. Introduction An understanding of the effects of temperature on wettability and relative permeability functions is essential to optimize and forecast the results of diatomite thermal-recovery projects. Most of the controversy regarding the effect of temperature on relative permeability is caused by the mechanisms involved in rock-wettability change that are dependent on both fluid and rock characteristics. A secondary, and equally important, problem is the technique used to process the data, such as oil recovery, phase saturation, or pressure, as well as data interpretation in the form of relative permeability curves. This paper re-examines the influence of temperature on rock/fluid interactions and heavy-oil relative permeability of diatomite from a core-level experimental and a pore-level perspective. We find experimentally and theoretically that fine particles are released from pore walls under conditions of elevated temperature, high pH, and moderate to low aqueous-phase salinity. The release of fines correlates with changes in relative permeability curves toward greater water-wetness. The mechanism of fines release provides new understanding of a mode of wettability alteration at elevated temperature. This paper is organized as follows. First, a synopsis of the literature is presented, followed by a discussion of recent developments in the understanding of wettability alteration. Second, the experimental method and the relative permeability interpretative methodology are outlined. Third, relative permeability results interpreted from field core samples at temperature are presented. Discussion and conclusions round out the paper.

[18F]Fluoride PET Indicates Reduced Bone Formation in Severe Glucocorticoid-induced Osteoporosis

1998 ◽  
Vol 37 (02) ◽  
pp. 76-79 ◽  
Author(s):  
T. D. Kirchhoff ◽  
W. Burchert ◽  
J. v. d. Hoff ◽  
H. Zeidler ◽  
H. Hundeshagen ◽  
...  
Keyword(s):  
Bone Formation ◽  
Multiple Organ ◽  
High Dose ◽  
Multiple Fractures ◽  
Glucocorticoid Treatment ◽  
Organ Manifestations ◽  
Diagnostic Benefit ◽  
Sharp Syndrome ◽  
18F Fluoride

SummaryA 61-year-old female patient presenting with mixed connective tissue disease (Sharp syndrome), underwent a long-term high dose glucocorticoid treatment because of multiple organ manifestations. Under steroid therapy she developed severe osteoporosis resulting in multiple fractures. A dynamic [18F]fluoride PET study in this patient revealed reduced fluoride influx in non-fractured vertebrae. This finding corresponds to pathogenetic concepts which propose an inhibition of bone formation as major cause of glucocorticoid-induced osteoporosis. In the light of the presented case it seems to be promising to evaluate the diagnostic benefit of [18F]fluoride PET in osteoporosis.

Status and Degree of Dysphagia in the Elderly-A Comparison Study of Long-Term Care Elderly People in an Outpatient Clinic

2003 ◽  
Vol 54 (4) ◽  
pp. 277-284 ◽  
Author(s):  
Masanori Komatsu ◽  
Kayoko Hirata ◽  
Idumi Mochimatsu ◽  
Kazuo Matsui ◽  
Hajime Hirose ◽  
...  
Keyword(s):  
Elderly People ◽  
Outpatient Clinic ◽  
Long Term Care ◽  
The Elderly ◽  
Comparison Study ◽  
Term Care
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