DEVELOPMENT OF WELLBORE TREATMENT TECHNOLOGY FOR IMPROVING PRODUCTION EFFICIENCY FROM AUSTRALIAN OIL AND GAS WELLS

1994 ◽  
Vol 34 (1) ◽  
pp. 79
Author(s):  
M.M. Rahman ◽  
F.A. Khan ◽  
S.S. Rahman
Keyword(s):  
Production Efficiency ◽  
Oil And Gas ◽  
Threshold Value ◽  
Honeycomb Structure ◽  
Formation Damage ◽  
Treatment Technology ◽  
Matrix Acidizing ◽  
Porosity And Permeability ◽  
Permeability Impairment ◽  
Completion Fluids

Low permeability or formation damage during drilling and completion procedures is often a serious threat to the economic development of a series of Australian oil and gas reserves. In this paper the Pacoota Sandstone in the Amadeus Basin has been considered and the effects of clay mineral morphology, water shock, type and concentration of different salts and varying flow velocity on fines migration were studied. Possible formation damage due to completion fluids and remedial measures such as matrix acidizing were also evaluated.The Pacoota Sandstone has been found to be sensitive to the salt concentration of permeating fluids. If the concentration falls below a threshold value, permeability begins to decrease drastically. Permeability impairment may further be aggravated if the flow rate of the permeating fluid reaches beyond a critical value. It has also been observed that the typical completion fluid reduces the permeability of the near wellbore region to almost half the original permeability. Use of CMHEC base chalk mud, however, reduces the water loss and consequently the permeability impairment by forming an internal filter cake with a typical honeycomb structure. Mud acid with less than 2.5 per cent HF acid concentration has been found to be insufficient to enhance porosity and permeability of the studied sandstone, rather it reduces the permeability by creating formation fines. Afterflush with EGMBE (10 per cent by volume) and HCl acid also helps to clean-up the small fines created during acidizing. The overall increase in porosity and permeability occurs mainly due to formation of large pore channels by matrix dissolution.

The Feasibility for Potassium-Based Phosphate Brines To Serve as High-Density Solid-Free Well-Completion Fluids in High-Temperature/High-Pressure Formations

SPE Journal ◽  
2018 ◽  
Vol 24 (05) ◽  
pp. 2033-2046 ◽  
Author(s):  
Hu Jia ◽  
Yao–Xi Hu ◽  
Shan–Jie Zhao ◽  
Jin–Zhou Zhao
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Oil And Gas ◽  
Pressure Coefficient ◽  
High Density ◽  
Well Drilling ◽  
Well Completion ◽  
Oil And Gas Resources ◽  
Completion Fluids ◽  
High Temperature High Pressure

Summary Many oil and gas resources in deep–sea environments worldwide are often located in high–temperature/high–pressure (HT/HP) and low–permeability reservoirs. The reservoir–pressure coefficient usually exceeds 1.6, with formation temperature greater than 180°C. Challenges are faced for well drilling and completion in these HT/HP reservoirs. A solid–free well–completion fluid with safety density greater than 1.8 g/cm3 and excellent thermal endurance is strongly needed in the industry. Because of high cost and/or corrosion and toxicity problems, the application of available solid–free well–completion fluids such as cesium formate brines, bromine brines, and zinc brines is limited in some cases. In this paper, novel potassium–based phosphate well–completion fluids were developed. Results show that the fluid can reach the maximum density of 1.815 g/cm3 at room temperature, which makes a breakthrough on the density limit of normal potassium–based phosphate brine. The corrosion rate of N80 steel after the interaction with the target phosphate brine at a high temperature of 180°C is approximately 0.1853 mm/a, and the regained–permeability recovery of the treated sand core can reach up to 86.51%. Scanning–electron–microscope (SEM) pictures also support the corrosion–evaluation results. The phosphate brine shows favorable compatibility with the formation water. The biological toxicity–determination result reveals that it is only slightly toxic and is environmentally acceptable. In addition, phosphate brine is highly effective in inhibiting the performance of clay minerals. The cost of phosphate brine is approximately 44 to 66% less than that of conventional cesium formate, bromine brine, and zinc brine. This study suggests that the phosphate brine can serve as an alternative high–density solid–free well–completion fluid during well drilling and completion in HT/HP reservoirs.

Experimental Investigation of Asphaltene-Induced Formation Damage Caused by Pressure Depletion of Live Reservoir Fluids in Porous Media

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 01-20 ◽  
Author(s):  
Omid Mohammadzadeh ◽  
Shawn David Taylor ◽  
Dmitry Eskin ◽  
John Ratulowski
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Flow Rate ◽  
Formation Damage ◽  
Bulk Fluid ◽  
Asphaltene Content ◽  
Pressure Depletion ◽  
Asphaltene Deposition ◽  
Permeability Impairment ◽  
Live Oil

Summary One of the complex processes of permeability impairment in porous media, especially in the near-wellbore region, is asphaltene-induced formation damage. During production, asphaltene particles precipitate out of the bulk fluid phase because of pressure drop, which might result in permeability reduction caused by both deposition of asphaltene nanoparticles on porous-medium surfaces and clogging of pore throats by larger asphaltene agglomerates. Experimental data will be used to identify the parameters of an impairment model being developed. As part of a larger effort to identify key mechanisms of asphaltene deposition in porous media and develop a model for asphaltene impairment by pressure depletion, this paper focuses on a systematic design and execution of an experimental study of asphaltene-related permeability damage caused by live-oil depressurization along the length of a flow system. An experiment was performed using a custom-designed 60-ft slimtube-coil assembly packed with silica sands to a permeability of 55 md. The customized design included a number of pressure gauges at regular intervals along the coil length, which enabled real-time measurement of the fluid-pressure profile across the full length of the slimtube coil. The test was performed on a well-characterized recombined live oil from the Gulf of Mexico (GOM) that is a known problematic asphaltenic oil. Under a constant differential pressure, the injection flow rate of the live oil through the slimtube coil decreased over time as the porous medium became impaired. During the impairment stage, samples of the produced oil were collected on a regular basis for asphaltene-content measurement. After more than 1 month, the impairment test was terminated; the live oil was purged from the slimtube coil with helium at a pressure above the asphaltene-onset pressure (AOP); and the entire system was gently depressurized to bring the coil to atmospheric conditions while preserving the asphaltene-damaged zones of the coil. The permeability and porosity of the porous medium changed because of asphaltene impairment that was triggered by pressure depletion. Results indicated that the coil permeability was impaired by approximately 32% because of pressure depletion below the AOP, with most of the damage occurring in the latter section of the tube, which operated entirely below the AOP. Post-analytical studies indicated lower asphaltene content of the produced-oil samples compared with the injecting fluid. The distribution of asphaltene deposits along the length of the coil was determined by cutting the slimtube coil into 2- to 3-ft-long sections and using solvent extraction to collect the asphaltenes in each section. The extraction results confirmed that the observed permeability impairment was indeed caused by asphaltene deposition in the middle and latter sections of the coil, where the pressure was less than the AOP. With the success of this experiment, the same detailed analysis can be extended to a series of experiments to determine the effects of different key parameters on pressure-induced asphaltene impairment, including flow rate, wettability, and permeability.

An Integrated Simulation Approach to Predict Permeability Impairment under Simultaneous Aggregation and Deposition of Asphaltene Particles

SPE Journal ◽  
2021 ◽  
pp. 1-14
Author(s):  
Xin Su ◽  
Rouzbeh G. Moghanloo ◽  
Minhui Qi ◽  
Xiang-an Yue
Keyword(s):  
Porous Media ◽  
Particle Aggregation ◽  
Formation Damage ◽  
Permeability Reduction ◽  
Simulation Approach ◽  
Pore Connectivity ◽  
Integrated Simulation ◽  
Asphaltene Deposition ◽  
Simulation Results ◽  
Permeability Impairment

Summary Formation damage mechanisms in general lower the quality of the near wellbore, often manifested in the form of permeability reduction, and thus reducing the productivity of production wells and injectivity of injection wells. Asphaltene deposition, as one of the important causes, can trigger serious formation damage issues and significantly restrict the production capacity of oil wells. Several mechanisms acting simultaneously contribute to the complexity associated with prediction of permeability impairment owing to asphaltene deposition; thus, integration of modeling efforts for asphaltene aggregation and deposition mechanisms seems inevitable for improved predictability. In this work, an integrated simulation approach is proposed to predict permeability impairment in porous medium. The proposed approach is novel because it integrates various mathematical models to study permeability impairment considering porosity reduction, particle aggregation, and pore connectivity loss caused by asphaltene deposition. To improve the accuracy of simulation results, porous media is considered as a bundle (different size) of capillary tubes with dynamic interconnectivity. The total volume change of interconnected tubes will directly represent permeability reduction realized in porous media. The prediction of asphaltene deposition in porous media is improved in this paper via integration of the particle aggregation model into calculation. The simulation results were verified by comparing with existing experimental data sets. After that, a sensitivity analysis was performed to study parameters that affect permeability impairment. The simulation results show that our permeability impairment model—considering asphaltene deposition, aggregation, and pore connectivity loss—can accurately reproduce the experimental results with fewer fitting or empirical parameters needed. The sensitivity analysis shows that longer aggregation time, higher flow velocity, and bigger precipitation concentration will lead to a faster permeability reduction. The findings of this study can help provide better understanding of the permeability impairment caused by asphaltene deposition and pore blockage, which provides useful insights for prediction of production performance of oil wells.

Prediction of Sand Production Through Porous Media: Mechanisms and Challenges to Optimising the Inefficiencies

2021 ◽  
Vol 18 (4) ◽  
pp. 45-52
Author(s):  
Wenhua Huang ◽  
Yan Huang ◽  
Juan Ren ◽  
Jinglong Jiang ◽  
Marischa Elveny
Keyword(s):  
Production Rate ◽  
Oil And Gas ◽  
Phenol Formaldehyde ◽  
Fundamental Issue ◽  
Sand Production ◽  
Drag Forces ◽  
Induced Drag ◽  
Porosity And Permeability ◽  
Production Conditions ◽  
Methods Of Control

One of the challenges facing drilling companies in the completion and production of oil and gas wells is sand production from the formation. The ability to predict sand production in the wells of a reservoir, to decide to use different methods of control is considered a fundamental issue. Therefore, analysis and study of sand production conditions and selecting the optimal drilling route before drilling wells are significant issues that are less considered. According to the findings of this study, due to the sand grains adhesion issue, saturation increase has caused to increase in the intermolecular uptake, and therefore moisture has been decreased. It leads to reduction in the sand production rate. Pressure increase has a direct relationship with the sand production rate due to increased induced drag forces. Moreover, phenol–formaldehyde resins provided an acceptable measurement as there are no significant changes in porosity and permeability.

Experimental Evaluation of a New Nonaromatic Nonionic Surfactant for Deep Carbonate Stimulation

2021 ◽  
pp. 1-12
Author(s):  
Khatere Sokhanvarian ◽  
Cornell Stanciu ◽  
Jorge M. Fernandez ◽  
Ahmed Farid Ibrahim ◽  
Harish Kumar ◽  
...  
Keyword(s):  
Nonionic Surfactant ◽  
Pore Volume ◽  
Inductively Coupled Plasma ◽  
Oil And Gas ◽  
Low Cost ◽  
Acid System ◽  
Matrix Acidizing ◽  
High Corrosion ◽  
First Choice ◽  
The Stability

Summary Matrix acidizing improves productivity in oil and gas wells. Hydrochloric acid (HCl), because of its many advantages such as its effectiveness, availability, and low cost, has been a typical first-choice fluid for acidizing operations. However, HCl in high-pressure/high-temperature (HP/HT) wells can be problematic because of its high reactivity, resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. Several alternatives to HCl have been tested; among them, emulsified acid is a favorable choice because of its inherent low corrosion rate, deeper penetration into the reservoir, fewer asphaltene/sludge problems, and better acid distribution due to its higher viscosity. The success of the new system is dependent upon the stability of the emulsion, especially at high temperatures. The emulsified acid must be stable until it is properly placed, and it must also be compatible with other additives in an acidizing package. This study develops a stable, emulsified acid system at 300°F using aliphatic nonionic surfactants. This paper introduces a new nonaromatic, nonionic surfactant to form an emulsified acid for HP/HT wells. The type and quality of the emulsified acid were assessed through conductivity measurements and drop tests. The thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. A LUMisizer® (LUM GmbH, Berlin, Germany) and Turbiscan® (Formulaction, S. A., L’Union, France) were used to determine the stability and the average droplet size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 300°F as a function of shear rate (1 to 1,000 s−1). The microscopy study was used to examine the shape and the distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes in carbonate rocks. Inductively coupled plasma and computed tomography (CT) scans were used to determine the dissolved cations and wormhole propagation, respectively. Superior stimulation results with a low pore volume of acid to breakthrough (PVBT) were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branched wormholes resulting from conventional emulsified acid systems. Results indicate that a nonionic surfactant with optimal chemistry, such as a suitable hydrophobe chain length and structure, can form a stable emulsified acid. In this study we introduce a new and effective aliphatic nonionic surfactant to create a stable emulsified acid system for matrix acidizing at HP/HT conditions, leading to a deeper penetration of acid with low pore volume to breakthrough. The successful core flood studies in the laboratory using carbonate cores suggest that the new emulsified acid system may efficiently stimulate HP/HT carbonate reservoirs.

scholarly journals Disaggregation and discretization methods for formation damage estimation in oil and gas fields: an overview

DYNA ◽  
2020 ◽  
Vol 87 (213) ◽  
pp. 105-115
Author(s):  
Oscar E Medina ◽  
Juan P Castaño-Correa ◽  
Cristina Caro-Vélez ◽  
Richard D Zabala ◽  
Jorge I Bahamón ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Formation Damage ◽  
Damage Estimation ◽  
Rock System ◽  
Discretization Methods ◽  
Oil And Gas Fields ◽  
Industrial Sectors ◽  
Damage Quantification ◽  
Gas Fields ◽  
Physical Changes

Formation damage could potentially impede production and injection operations. Hence, characterization and discretization processes of formation damage should be connected to quantification and disaggregation techniques, relying on characterization fundamentals that consider chemical and physical changes in the fluid and rock system through the field productive life. This document presents a review of different disaggregation, quantification and discretization methods for the formation damage estimation in oil and gas fields. This review is mainly divided into three main sections, namely: i) Formation damage diagnosis, ii) Formation damage quantification, and iii) Formationdamage disaggregation. This document will aid in the alignment of the academic and industrial sectors to incentivize the prevention and inhibition of formation damage, as well as the optimal design of remediation mechanisms.

scholarly journals Modeling and Simulation of Flow and Formation Damage of Asphalt-Paved Roads

2013 ◽  
Vol 2013 ◽  
pp. 1-5
Author(s):  
M. H. Alawi ◽  
M. M. El-Qadi ◽  
M. A. El-Ameen
Keyword(s):  
Mathematical Modeling ◽  
Suspended Solids ◽  
Fine Particles ◽  
Water Saturation ◽  
Formation Damage ◽  
Phase Flow ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Porous Asphalt ◽  
Porosity And Permeability

Porous asphalt is a standard asphalt built on aggregate storage bed which allows water to drain through it and reduces stormwater runoff. However, porosity of the porous asphalt and the storage bed may be effectively reduced due to trapping suspended solids from the water or from the asphalt damage. In this paper, we present mathematical modeling and numerical simulation of flow and damage of porous asphalt-paved roads. A mathematical model to describe the fine-particles transport carried by a two-phase flow in a porous medium is presented. The buoyancy, capillarity, and mixed relative permeabilities correlations to fit with the mixed-wet system are considered. Throughout this investigation, we monitor the changing of the fluids properties such as water saturation and solid properties such as porosity and permeability due to trapping the fine-particles.

Transient Pressure Behavior and Formation Damage Evolution of Wells During Matrix-Acidizing Operations

1990 ◽  
Author(s):  
F. Rodriguez ◽  
J.M. Sanchez-B. ◽  
H. Cinco-Ley
Keyword(s):  
Damage Evolution ◽  
Formation Damage ◽  
Transient Pressure ◽  
Matrix Acidizing ◽  
Pressure Behavior
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