Prevention of Water-Blocking Formation Damage in Gas Reservoirs Wettability Alteration, Analytical Modelling

2016 ◽  
Author(s):  
Saurabh Naik ◽  
Zhenjiang You ◽  
Pavel Bedrikovetsky
Keyword(s):  
Analytical Modelling ◽  
Wettability Alteration ◽  
Formation Damage ◽  
Gas Reservoirs ◽  
Water Blocking

Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 397-407 ◽  
Author(s):  
Mashhad Mousa Fahes ◽  
Abbas Firoozabadi
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
High Temperatures ◽  
Gas Production ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Absolute Permeability ◽  
Low Permeability ◽  
Gas Well ◽  
Water Blocking

Summary Wettability of two types of sandstone cores, Berea (permeability on the order of 600 md), and a reservoir rock (permeability on the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90C. In this work, chemicals previously used at 90C for wettability alteration are found to be ineffective at 140C. New chemicals are used which alter wettability at high temperatures. The results show that:wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures,wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions,wettability alteration results in improved gas productivity, andwettability alteration does not have a measurable effect on the absolute permeability of the rock for some chemicals. We also find the reservoir rock, unlike Berea, is not strongly water-wet in the gas/water/rock system. Introduction A sharp reduction in gas well deliverability is often observed in many low-permeability gas-condensate reservoirs even at very high reservoir pressure. The decrease in well deliverability is attributed to condensate accumulation (Hinchman and Barree 1985; Afidick et al. 1994) and water blocking (Engineer 1985; Cimolai et al. 1983). As the pressure drops below the dewpoint, liquid accumulates around the wellbore in high saturations, reducing gas relative permeability (Barnum et al. 1995; El-Banbi et al. 2000); the result is a decrease in the gas production rate. Several techniques have been used to increase gas well deliverability after the initial decline. Hydraulic fracturing is used to increase absolute permeability (Haimson and Fairhurst 1969). Solvent injection is implemented in order to remove the accumulated liquid (Al-Anazi et al. 2005). Gas deliverability often increases after the reduction of the condensate saturation around the wellbore. In a successful methanol treatment in Hatter's Pond field in Alabama (Al-Anazi et al. 2005), after the initial decline in well deliverability by a factor of three to five owing to condensate blocking, gas deliverability increased by a factor of two after the removal of water and condensate liquids from the near-wellbore region. The increased rates were, however, sustained for a period of 4 months only. The approach is not a permanent solution to the problem, because the condensate bank will form again. On the other hand, when hydraulic fracturing is used by injecting aqueous fluids, the cleanup of water accumulation from the formation after fracturing is essential to obtain an increased productivity. Water is removed in two phases: immiscible displacement by gas, followed by vaporization by the expanding gas flow (Mahadevan and Sharma 2003). Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2003; Penny et al. 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al. 1989; Sognesand 1991; Baig et al. 2005).

Technology Focus: Unconventional and Tight Reservoirs (July 2021)

2021 ◽  
Vol 73 (07) ◽  
pp. 57-57
Author(s):  
Leonard Kalfayan
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Alternative Methods ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Liquid Loading ◽  
Well Production ◽  
Tight Carbonate ◽  
Water Blocking ◽  
Tight Reservoirs

As unconventional oil and gas fields mature, operators and service providers are looking toward, and collaborating on, creative and alternative methods for enhancing production from existing wells, especially in the absence of, or at least the reduction of, new well activity. While oil and gas price environments remain uncertain, recent price-improvement trends are supporting greater field testing and implementation of innovative applications, albeit with caution and with cost savings in mind. Not only is cost-effectiveness a requirement, but cost-reducing applications and solutions can be, too. Of particular interest are applications addressing challenging well-production needs such as reducing or eliminating liquid loading in gas wells; restimulating existing, underperforming wells, including as an alternative to new well drilling and completion; and remediating water blocking and condensate buildup, both of which can impair production from gas wells severely. The three papers featured this month represent a variety of applications relevant to these particular well-production needs. The first paper presents a technology and method for liquid removal to improve gas production and reserves recovery in unconventional, liquid-rich reservoirs using subsurface wet-gas compression. Liquid loading, a recurring issue downhole, can severely reduce gas production and be costly to remediate repeatedly, which can be required. This paper discusses the full technology application process and the supportive results of the first field trial conducted in an unconventional shale gas well. The second paper discusses the application of the fishbone stimulation system and technique in a tight carbonate oil-bearing formation. Fishbone stimulation has been around for several years now, but its best applications and potential have not necessarily been fully understood in the well-stimulation community. This paper summarizes a successful pilot application resulting in a multifold increase in oil-production rate and walks the reader through the details of the pilot candidate selection, completion design, operational challenges, and lessons learned. The third paper introduces and proposes a chemical treatment to alleviate phase trapping in tight carbonate gas reservoirs. Phase trapping can be in the form of water blocking or increasing condensate buildup from near the wellbore and extending deeper into the formation over time. Both can reduce relative permeability to gas severely. Water blocks can be a one-time occurrence from drilling, completion, workover, or stimulation operations and can often be treated effectively with solvent plus proper additive solutions. Similar treatments for condensate banking in gas wells, however, can provide only temporary alleviation, if they are even effective. This paper proposes a technique for longer-term remediation of phase trapping in tight carbonate gas reservoirs using a unique, slowly reactive fluid system. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200345 - Insights Into Field Application of Enhanced-Oil-Recovery Techniques From Modeling of Tight Reservoirs With Complex High-Density Fracture Network by Geng Niu, CGG, et al. SPE 201413 - Diagnostic Fracture Injection Test Analysis and Simulation: A Utica Shale Field Study by Jeffery Hildebrand, The University of Texas at Austin, et al.

Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations

2005 ◽  
Vol 127 (3) ◽  
pp. 240-247 ◽  
Author(s):  
D. Brant Bennion ◽  
F. Brent Thomas
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
The United States ◽  
Gas Production ◽  
Pressure Effects ◽  
Formation Damage ◽  
Low Permeability ◽  
Gas Reservoirs ◽  
Initial Water ◽  
The Impact

Very low in situ permeability gas reservoirs (Kgas<0.1mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

Experimental Study of Wettability Alteration to Preferential Gas-Wetting in Porous Media and Its Effects

2000 ◽  
Vol 3 (02) ◽  
pp. 139-149 ◽  
Author(s):  
Li Kewen ◽  
Firoozabadi Abbas
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Capillary Tube ◽  
Gas Condensate ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Glass Capillary ◽  
Gas Reservoirs ◽  
Gas Well ◽  
Gas Condensate Reservoirs

Summary In a recent theoretical study, Li and Firoozabadi [Li, K. and Firoozabadi, A.: "Phenomenological Modeling of Critical-Condensate Saturation and Relative Permeabilities in Gas-Condensate Systems," paper SPE 56014 available from SPE, Richardson, Texas (2000)] showed that if the wettability of porous media can be altered from preferential liquid-wetting to preferential gas-wetting, then gas-well deliverability in gas-condensate reservoirs can be increased. In this article, we present the results that the wettability of porous media may indeed be altered from preferential liquid-wetting to preferential gas-wetting. In the petroleum literature, it is often assumed that the contact angle through liquid-phase ? is equal to 0° for gas-liquid systems in rocks. As this work will show, while ? is always small, it may not always be zero. In laboratory experiments, we altered the wettability of porous media to preferential gas-wetting by using two chemicals, FC754 and FC722. Results show that in the glass capillary tube ? can be altered from about 50 to 90° and from 0 to 60° by FC754 for water-air and normal decane-air systems, respectively. While untreated Berea saturated with air has a 60% imbibition of water, its imbibition of water after chemical treatment is almost zero and its imbibition of normal decane is substantially reduced. FC722 has a more pronounced effect on the wettability alteration to preferential gas-wetting. In a glass capillary tube ? is altered from 50 to 120° and from 0 to 60° for water-air and normal decane-air systems, respectively. Similarly, because of wettability alteration with FC722, there is no imbibition of either oil or water in both Berea and chalk samples with or without initial brine saturation. Entry capillary pressure measurements in Berea and chalk give a clear demonstration that the wettability of porous media can be permanently altered to preferential gas-wetting. Introduction In a theoretical work,1 we have modeled gas and liquid relative permeabilities for gas-condensate systems in a simple network. The results imply that when one alters the wettability of porous media from strongly non-gas-wetting to preferential gas-wetting or intermediate gas-wetting, there may be a substantial increase in gas-well deliverability. The increase in gas-well deliverability of gas-condensate reservoirs is our main motivation for altering the wettability of porous media to preferential gas-wetting. Certain gas-condensate reservoirs experience a sharp drop in gas-well deliverability when the reservoir pressure drops below the dewpoint.2–4 Examples include many rich gas-condensate reservoirs that have a permeability of less than 100 md. In these reservoirs, it seems that the viscous forces alone cannot enhance gas-well deliverability. One may suggest removing liquid around the wellbore via phase-behavior effects through CO2 and propane injection. Both have been tried in the field with limited success; the effect of fluid injection around the wellbore for the removal of the condensate liquid is temporary. Wettability alteration can be a very important method for the enhancement of gas-well deliverability. If one can alter the wettability of the wellbore region to intermediate gas-wetting, gas may flow efficiently in porous media. As early as 1941, Buckley and Leverett5 recognized the importance of wettability on water flooding performance. Later, many authors studied the effect of wettability on capillary pressure, relative permeability, initial water saturation, residual oil saturation, oil recovery, electrical properties of reservoir rocks, reserves, and well stimulation.6–16 reported that it might be possible to improve oil displacement efficiency by wettability adjustment during water flooding. In 1967, Froning and Leach8 reported a field test in Clearfork and Gallup reservoirs for improving oil recovery by wettability alteration. Kamath9 then reviewed wettability detergent flooding. He noted that it was difficult to draw a definite conclusion regarding the success of detergent floods from the data available in the literature. Penny et al.12 presented a technique to improve well stimulation by changing the wettability for gas-water-rock systems. They added a surfactant in the fracturing fluid. This yielded impressive results; the production following cleanup after fracturing in gas wells generally was 2 to 3 times greater than field averages or offset wells treated with conventional techniques. Penny et al.12 believed that increased production was due to wettability alteration. However, they did not demonstrate that wettability had been altered. Recently, Wardlaw and McKellar17 reported that only 11% pore volume (PV) water imbibed into the Devonian dolomite samples with bitumen. The water imbibition test was conducted vertically in a dry core (saturated with air). Based on the imbibition experiments, they pointed out that many gas reservoirs in the western Alberta foothills of the Rocky Mountains were partially dehydrated and their wettability altered to a weakly water-wet or strongly oil-wet condition due to bitumen deposits on the pores. The water imbibition results of Wardlaw and McKellar17 demonstrated that the inappropriate hypothesis for wetting properties of gas reservoirs might lead to underestimation of hydrocarbon reserves.

scholarly journals Damage Mechanism of Oil-Based Drilling Fluid Flow in Seepage Channels for Fractured Tight Sandstone Gas Reservoirs

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-15 ◽  
Author(s):  
Peng Xu ◽  
Mingbiao Xu
Keyword(s):  
Drilling Fluid ◽  
Damage Control ◽  
Damage Mechanism ◽  
Formation Damage ◽  
Drilling Fluids ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Stabilization Effect ◽  
Potential Damage ◽  
Physical And Chemical

Oil-based drilling fluids (OBDFs) have a strong wellbore stabilization effect, but little attention has been paid to the formation damage caused by oil-based drilling fluids based on traditional knowledge, which is a problem that must be solved prior to the application of oil-based drilling fluid. For ultradeep fractured tight sandstone gas reservoirs, the reservoir damage caused by oil-based drilling fluids is worthy of additional research. In this paper, the potential damage factors of oil-based drilling fluids and fractured tight sandstone formations are analyzed theoretically and experimentally. The damage mechanism of oil-based drilling fluids for fractured tight sandstone gas reservoirs is analyzed based on the characteristics of multiphase fluids in seepage channels, the physical and chemical changes of rocks, and the rheological stability of oil-based drilling fluids. Based on the damage mechanism of oil-based drilling fluids, the key problems that must be solved during the damage control of oil-based drilling fluids are analyzed, a detailed description of formation damage characteristics is made, and how to accurately and rapidly form plugging zones is addressed. This research on damage control can provide a reference for solving the damage problems caused by oil-based drilling fluids in fractured tight sandstone gas reservoirs.

Fracturing in Tight-Gas Reservoirs: Application of SCAL Methods To Investigate Formation-Damage Mechanisms

2008 ◽  
Author(s):  
Brigitte Bazin ◽  
Samir Bekri ◽  
Olga Vizika ◽  
Benjamin Herzhaft ◽  
Eric Aubry
Keyword(s):  
Formation Damage ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Damage Mechanisms ◽  
Tight Gas Reservoirs
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