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).

Numerical Investigation on Multiphase Erosion-Corrosion Problem of Steel of Apparatus at a Well Outlet in Natural Gas Production

2018 ◽  
Vol 140 (12) ◽  
Author(s):  
Zhang Jianwen ◽  
Jiang Aiguo ◽  
Xin Yanan ◽  
He Jianyun
Keyword(s):  
Fluid Flow ◽  
Natural Gas ◽  
Production Rate ◽  
Gas Production ◽  
Two Phase ◽  
Gas Well ◽  
Chemical Corrosion ◽  
High Production Rate ◽  
Erosion Corrosion ◽  
Corrosion Problem

The erosion-corrosion problem of gas well pipeline under gas–liquid two-phase fluid flow is crucial for the natural gas well production, where multiphase transport phenomena expose great influences on the feature of erosion-corrosion. A Eulerian–Eulerian two-fluid flow model is applied to deal with the three-dimensional gas–liquid two-phase erosion-corrosion problem and the chemical corrosion effects of the liquid droplets dissolved with CO2 on the wall are taken into consideration. The amount of erosion and chemical corrosion is predicted. The erosion-corrosion feature at different parts including expansion, contraction, step, screw sections, and bends along the well pipeline is numerically studied in detail. For dilute droplet flow, the interaction between flexible water droplets and pipeline walls under different operations is treated by different correlations according to the liquid droplet Reynolds numbers. An erosion-corrosion model is set up to address the local corrosion and erosion induced by the droplets impinging on the pipe surfaces. Three typical cases are studied and the mechanism of erosion-corrosion for different positions is investigated. It is explored by the numerical simulation that the erosion-corrosion changes with the practical production conditions: Under lower production rate, chemical corrosion is the main cause for erosion-corrosion; under higher production rate, erosion predominates greatly; and under very high production rate, erosion becomes the main cause. It is clarified that the parts including connection site of oil pipe, oil pipe set, and valve are the places where erosion-corrosion origins and becomes serious. The failure mechanism is explored and good comparison with field measurement is achieved.

scholarly journals Analysis of chemical volume and composition to overcome liquid loading in gas well

2018 ◽  
Vol 67 ◽  
pp. 03009
Author(s):  
Abdul Wahid ◽  
Muhamad Taufiq Hidayat
Keyword(s):  
Natural Gas ◽  
Water Content ◽  
Production Rate ◽  
Gas Production ◽  
Reservoir Pressure ◽  
Liquid Loading ◽  
Critical Rate ◽  
Gas Well ◽  
Natural Gas Production ◽  
Drive Mechanism

Many problems often occur in producing natural gas from well. Due to the existence of water content in natural gas or water drive mechanism, liquid (especially water) is also produced from gas well, following natural gas production. When gas critical rate is higher than gas production rate due to reservoir pressure decline, it will cause liquid accumulation in the bottom of well, avoiding natural gas to be well lifted from well bottom to surface. It is liquid loading. Chemical injection of 0.4 liquid that consists of ethoxy sulphate, alkane sulphonate, and petroleum sulphonate is effective to overcome liquid loading in natural gas well thus causing an increase in natural gas production by 57%.

scholarly journals Influence of Intrinsic Permeability on the Production Performance of Shenhu Hydrate Sediment through Depressurization

2019 ◽  
Vol 118 ◽  
pp. 01008
Author(s):  
Yingrui Ma ◽  
Shuxia Li ◽  
Didi Wu
Keyword(s):  
Production Rate ◽  
Gas Production ◽  
Production Performance ◽  
Absolute Permeability ◽  
Reservoir Pressure ◽  
Intrinsic Permeability ◽  
Reservoir Temperature ◽  
Natural Gas Hydrate ◽  
Hydrate Dissociation ◽  
Hydrate Reservoirs

Natural gas hydrate(NGH) is a clean resource with huge reserves. The depressurization method is an economical and effective exploitation method. In the process of depressurization, reservoir absolute permeability has an important influence on production results. Based on the data of Shenhu hydrate reservoirs, this paper established a depressurization production numerical simulation model. Then, the production performances such as pressure, temperature, gas production rate, cumulative gas production, and hydrate dissociation effect are all studied under different permeability conditions.study the change of reservoir pressure, gas production rate, cumulative gas production, reservoir temperature change and hydrate dissociation effect under different permeability conditions. Results show that higher permeability is conducive to the depressurization of hydrate reservoirs.

Flow physics of how surfactants can reduce water blocking caused by hydraulic fracturing in low permeability reservoirs

2017 ◽  
Vol 157 ◽  
pp. 631-642 ◽  
Author(s):  
Tianbo Liang ◽  
Sofiane H. Achour ◽  
Rafael A. Longoria ◽  
David A. DiCarlo ◽  
Quoc P. Nguyen
Keyword(s):  
Hydraulic Fracturing ◽  
Low Permeability ◽  
Flow Physics ◽  
Water Blocking ◽  
Low Permeability Reservoirs

scholarly journals Investigation on the CBM Extraction Techniques in the Broken-Soft and Low-Permeability Coal Seams in Zhaozhuang Coalmine

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Zhaoying Chen ◽  
Xuehai Fu ◽  
Guofu Li ◽  
Jian Shen ◽  
Qingling Tian ◽  
...  
Keyword(s):  
Coal Seam ◽  
Hydraulic Fracturing ◽  
Coalbed Methane ◽  
Research Result ◽  
Horizontal Stress ◽  
Gas Production ◽  
Vertical Stress ◽  
Low Permeability ◽  
Coal Seams

To enhance the coalbed methane (CBM) extraction in broken-soft coal seams, a method of drilling a horizontal well along the roof to hydraulically fracture the coal seam is studied (i.e., HWR-HFC method). We first tested the physical and mechanical properties of the broken-soft and low-permeability (BSLP) coal resourced from Zhaozhuang coalmine. Afterward, the in situ hydraulic fracturing test was conducted in the No. 3 coal seam of Zhaozhuang coalmine. The results show that (1) the top part of the coal seam is fractured coal, and the bottom is fragmented-mylonitic coal with a firmness coefficient value of less than 1.0. (2) In the hydraulic fracturing test of the layered rock-coal specimens in laboratory, the through-type vertical fractures are usually formed if the applied vertical stress is the maximum principal stress and is greater than 4 MPa compared with the maximum horizontal stress. However, horizontal fractures always developed when horizontal stress is the maximum or it is less than 4 MPa compared with vertical stress. (3) The in situ HWR-HFC hydraulic fracturing tests show that the detected maximum daily gas production is 11,000 m3, and the average gas production is about 7000 m3 per day. This implies that the CBM extraction using this method is increased by 50%~100% compared with traditional hydraulic fracturing in BSLP coal seams. The research result could give an indication of CBM developing in the broken-soft and low-permeability coal seams.

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%.

Well productivity enhancement by applying nanofluids for wettability alteration

2018 ◽  
Vol 58 (1) ◽  
pp. 121 ◽  
Author(s):  
Saurabh Naik ◽  
Gabriel Malgaresi ◽  
Zhenjiang You ◽  
Pavel Bedrikovetsky
Keyword(s):  
Contact Angle ◽  
Gas Production ◽  
Analytical Models ◽  
Wettability Alteration ◽  
Two Phase ◽  
Well Productivity ◽  
Productivity Decline ◽  
Water Blocking ◽  
Water Cut ◽  
Constant Contact Angle

Water blocking is a frequent cause for gas productivity decline in unconventional and conventional fields. It is a result of the capillary end effect near the wellbore vicinity. It creates significant formation damage and decreases gas well productivity. The alteration of the rock wettability by nanofluids is an effective way to reduce water blockage and enhance gas production. Presently, several types of surfactants and nanofluids are used in the industry for contact angle alteration. In this study, we developed an analytical model and analysed the sensitivity to several parameters. After the treatment, the porous medium in the well vicinity (or along the core) will have a stepwise constant contact angle profile. We derive analytical models for compressible steady-state two-phase linear and axi-symmetric flows, accounting for the piecewise-constant contact angle and contact-angle-dependent capillary pressure and relative permeability. The modelling reveals a complex interplay between the competing effects of compressibility, viscous and capillary forces, which influence the optimal contact angle for treatment. The optimal contact angle for treatment will depend on the initial wettability of the formation, the water cut and the capillary-viscous ratio.

scholarly journals Evolution of Production and Transport Characteristics of Steeply-Dipping Ultra-Thick Coalbed Methane Reservoirs

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5081 ◽  
Author(s):  
Shun Liang ◽  
Hao Han ◽  
Derek Elsworth ◽  
Xuehai Fu ◽  
Qiangling Yao ◽  
...  
Keyword(s):  
Production Rate ◽  
Coalbed Methane ◽  
Water Saturation ◽  
Initial Pressure ◽  
Gas Production ◽  
Low Rank ◽  
Absolute Permeability ◽  
Fluid Saturation ◽  
Cbm Production ◽  
Strong Control

The large spatial variability of in-situ stress and initial reservoir pressure in steeply-dipping ultra-thick coalbed methane (UTCBM) reservoirs exert strong control on the initial distribution of stress-sensitive permeability. This results in significant differences in the propagation of reservoir depressurization, gas production characteristics, distribution of fluid saturation, and evolution of permeability relative to flat-lying and thin counterpart coalbed methane (CBM) reservoirs. We contrast these responses using the Fukang mining area of the Junggar Basin, Xinjiang, China, as a type-example using coupled hydro-mechanical modeling. Production response indicates: (1) Dual peaks in CBM production rate, due to the asynchronous changes in the gas production rate in each the upper and lower sections of the reservoir; (2) higher depressurization and water saturation levels in the lower section of the reservoir relative to the upper at any given distance from the production well that ameliorate with time to be similar to those of standard horizontal reservoirs; (3) the heterogeneity in effective stress is further amplified by the asymmetry of the initial pressure drawdown distribution of the reservoir to exert extreme control on the down-dip evolution of absolute permeability—with implications for production. Field drainage data and simulation results obtained in this study more accurately reflect the drainage characteristics of the steeply-dipping UTCBM reservoirs. For ultra-thick low-rank coal seams, permeability anisotropy plays an important role in determining the utility of horizontal wells and hydraulic fracturing to maximize rates and yields CBM production, and requiring further study.

Productivity Loss in Gas Wells Caused by Salt Deposition

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 908-920 ◽  
Author(s):  
Duc Le ◽  
Jagannathan Mahadevan
Keyword(s):  
Productivity Loss ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Gas Well ◽  
Well Productivity ◽  
Salt Deposition ◽  
Remediation Strategies ◽  
Salt Crystals ◽  
Dimensionless Ratio ◽  
Porosity And Permeability

Summary Production of gas can result in drying of the near-wellbore region caused by gas expansion, which causes evaporation and hence salt deposition. The deposition of salt leads to a reduction in porosity and permeability of the rock in the near-wellbore region, which then leads to reduction in well productivity. The main objective of this work is to understand the role of capillarity on salt deposition and its impact on well flow efficiency. We develop and solve the dimensionless-conservation equations for solid-salt saturation using numerical methods under radial-flow conditions. The results of the calculations show that when the capillary effects are strong, the salt accumulates near the wellbore, which leads to plugging and hence higher skin values. The salt saturation continues to evolve until a limiting value, in the rock pores, is reached. Higher values of the limiting saturation lead to a greater reduction in permeability and therefore result in a larger skin value for the gas well. The flow efficiency of a gas well, calculated as a dimensionless ratio of the flow with and without skin, decreases continually and asymptotically approaches a constant value. In a simulation for a typical field case, we find that the largest increase in skin factor and corresponding decrease in flow efficiency occur in approximately the first 30 days, after which the changes are slower. When connate-water salt concentration is higher, the skin value is much higher and thus the well productivity is lower. Using the model developed in this study, the decline of gas-well productivity caused by salt deposition can be predicted and hence accurate timing of well operations, such as water wash, can be made. Also, the modeling study can be used to select remediation strategies such as wettability alteration to reduce capillarity or application of inhibitors, which can reduce the limiting salt saturation by preventing growth of salt crystals within the reservoir rock.

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