Research and Application of Compound Plugging Removal Technology in HTHP Condensate Gas Well

2021 ◽  
Author(s):  
Hongjun Wu ◽  
Kun Huang ◽  
Ju Liu ◽  
Bao Zhang ◽  
Jiquan Liu ◽  
...  
Keyword(s):  
Gas Production ◽  
Flow Channel ◽  
Acid System ◽  
Wax Deposition ◽  
Gas Wells ◽  
Gas Well ◽  
Coiled Tubing ◽  
Removal Technology ◽  
Single Well ◽  
Gas Fields

Abstract Dabei and Dina 2 gas fields located in Tarim Oilfield are HTHP and high production condensate gas fields. The formation temperature is 136°C, the formation pressure is 105MPa, the gas production of single well is 40×104m3/d~100×104m3/d, and the condensate production is 35t/d~86t/d. After the HTHP condensate gas well started production, the oil production pressure continues to fluctuate and decline due to the wellbore plugging. By 2019, more than 80% of the HTHP condensate gas wells have the wellbore plugging problem, gas production of some wells reduced over 50%, a few wells even shut in, the normal production of condensate gas well is seriously affected. In some condensate gas wells of Dabei gas field, organic plugging substances are obtained in the wellhead and the nearby oil pipes during the well passing and other operations. Wax is detected and analyzed as the plugging substance. In addition, inorganic plugging substances are obtained at the bottom of the production pipe in the wells with serious plugging, through the coiled tubing dredging and overhaul operations, which are mainly concentrated at the reducing tool or screen pipe. The content of inorganic scale in the plug is 60% ~ 90%, and the rest is a small amount of formation sand. In view of the problem of wax deposition on the upper part of the wellbore and plugging the tubing of the condensate gas well, the condensate oil samples and wellbore wax samples were obtained on site. The experiment analysis confirmed that the condensate oil dewax temperature is 37.1°C, which can provide a reference for judging whether the wellbore had wax deposition. In order to solve the problem of wax deposition in the wellbore, the laboratory evaluation experiment of wax remover optimization was carried out to optimize the wax remover with good wax dissolving effect. In view of the inorganic scale plugging at the lower part of the wellbore, the research on the scaling mechanism of high-pressure well bore was clarified, and the high dissolution and low corrosion solution acid system was optimized through the laboratory experiment. For the wells with wax deposition and scale compound blockage, but have flow channel, a compound plugging removal technology is formed, which is to inject wax remover to remove the wax plug in the upper part of the well, and then inject acid system to remove the scale plug in the lower part of the well. For the wells with serious well plugging, a compound plugging removal technology is formed, which is to dredge the well through coiled tubing to form a flow channel, and then inject acid solution to remove the scale plug in the lower part of the well. Three wells have successfully implemented wax and scale compound plug removal, and the average single well productivity after plug removal is 2.7 times of that before plug removal, At present, the production of DB2-A Well has been stable for 22 months after plug removal. three wells have successfully implemented "coiled tubing dredging + wellbore acid plugging removal" complex plug removal, and the production capacity has been successfully restored after operation, the average single well tubing pressure is 60.4MPa, and the total daily natural gas production is 178×104m3/d. HTHP condensate gas well wellbore compound plug removal technology can remove the organic and inorganic plugging in the wellbore to the high efficiency recovery of the well.

Technology of water shut-off treatment in the gas well using coiled tubing

2021 ◽  
pp. 75-85
Author(s):  
D. S. Leontiev ◽  
I. I. Kleshchenko ◽  
A. D. Shalyapina ◽  
M. M. Mansurova
Keyword(s):  
Bottom Water ◽  
Urgent Problem ◽  
Gas Wells ◽  
Flexible Pipe ◽  
Gas Field ◽  
Gas Well ◽  
Coiled Tubing ◽  
Bottom Hole ◽  
Water Saturated ◽  
Gas Fields

In the modern practice of gas field operation, there is a problem associated with the inflow of bottom water to the bottom hole of the well. One of the ways to solve this urgent problem is the introduction of water isolation technologies in the development of gas fields and the use of special compositions and technological equipment for pumping liquids into the watered layers of gas wells. The article deals with the application of a set of special technological measures, such as installation of surface equipment for working in a gas well using coiled tubing, descent of a flexible pipe through a column of pump and compressor pipes with a packer, construction of an inflatable packer, as well as the use of a selective water-insulating composition of the well by pumping it through existing perforation channels in the casing string. Liquids based on ethyl silicate create a kind water shut-off screen between the gas- saturated and water-saturated parts of the gas well formation.

Numerical Simulation Study on the Key Influencing Factors of Water-Invasion Performance for the Gas Wells with Bottom-Water

2014 ◽  
Vol 884-885 ◽  
pp. 104-107
Author(s):  
Zhi Jun Li ◽  
Ji Qiang Li ◽  
Wen De Yan
Keyword(s):  
Numerical Simulation ◽  
Influencing Factors ◽  
Bottom Water ◽  
Simulation Method ◽  
Gas Production ◽  
Production Performance ◽  
Gas Wells ◽  
Two Phase ◽  
Gas Well ◽  
Water Gas

For the water-sweeping gas reservoir, especially when the water-body is active, water invasion can play positive roles in maintaining formation pressure and keeping the gas well production. But when the water-cone break through and towards the well bottom, suffers from the influencing of gas-water two phase flows, permeability of gas phase decrease sharply and will have a serious impact on the production performance of the gas well. Moreover, the time when the water-cone breakthrough will directly affect the final recovery of the gas wells, therefore, the numerical simulation method is used to conduct the research on the key influencing factors of water-invasion performance for the gas wells with bottom-water, which is the basis of the mechanical model for the typical gas wells with bottom-water. It indicate that as followings: (1) the key influencing factors of water-invasion performance for the gas wells with bottom-water are those, such as the open degree of the gas beds, well gas production and the amount of Kv/Kh value; and (2) the barrier will be in charge of great significance on the water-controlling for the bottom water gas wells, and its radius is the key factor to affect water-invasion performance for the bottom water gas wells where the barriers exist nearby.

Well Completion for Effective Deliquification of Natural Gas Wells

2011 ◽  
Vol 134 (1) ◽  
Author(s):  
John Yilin Wang
Keyword(s):  
Natural Gas ◽  
Operating Cost ◽  
Gas Production ◽  
Gas Wells ◽  
Liquid Loading ◽  
Gas Recovery ◽  
Well Completion ◽  
Reservoir Permeability ◽  
Gas Fields ◽  
Gas Lift

Liquid loading has been a problem in natural gas wells for several decades. With gas fields becoming mature and gas production rates dropping below the critical rate, deliquification becomes more and more critical for continuous productivity and profitability of gas wells. Current methods for solving liquid loading in the wellbore include plunger lift, velocity string, surfactant, foam, well cycling, pumps, compression, swabbing, and gas lift. All these methods are to optimize the lifting of liquid up to surface, which increases the operating cost, onshore, and offshore. However, the near-wellbore liquid loading is critical but not well understood. Through numerical reservoir simulation studies, effect of liquid loading on gas productivity and recovery has been quantified in two aspects: backup pressure and near-wellbore liquid blocking by considering variable reservoir permeability, reservoir pressure, formation thickness, liquid production rate, and geology. Based on the new knowledge, we have developed well completion methods for effective deliquifications. These lead to better field operations and increased ultimate gas recovery.

Research Progress in Calculation Methods for Single-Well Dynamic Reserves of Gas Reservoirs

2014 ◽  
Vol 1044-1045 ◽  
pp. 401-405
Author(s):  
Hai Dong Shi
Keyword(s):  
High Efficiency ◽  
Research Progress ◽  
Calculation Methods ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Well Spacing ◽  
Well Pattern ◽  
Single Well ◽  
Gas Fields

Dynamic reserves are the important basis for determining the reasonable deliverability of gas wells and well spacing density and also the foundation for the overall development plan of a gas field. Therefore, the evaluation of dynamic reserves of gas wells is crucially important to developing gas fields with high efficiency, optimizing well pattern and shortening development period. For this reason, this paper arranges and analyzes systematically a series of calculation methods for dynamic reserves of single gas well, which have arisen in recent years, and identifies the calculation methods for different types of gas reservoirs.

Study on Source Analysis of the Cation in Produced Water from Sulige Gas Field and Anti-Scaling Measures

2019 ◽  
Vol 814 ◽  
pp. 505-510
Author(s):  
Peng Chang ◽  
Rui Xue Shi ◽  
Li Wang ◽  
Wei Han ◽  
Cong Dan Ye ◽  
...  
Keyword(s):  
Produced Water ◽  
Xrd Analysis ◽  
Source Analysis ◽  
Scale Inhibitor ◽  
Gas Wells ◽  
Gas Field ◽  
Gas Well ◽  
Strontium Sulfate ◽  
Single Well ◽  
Main Component

A large amount of foreign matter appears in the Sulige gas well, causing blockage and corrosion of the pipeline, increasing the pressure difference in the wellbore and seriously affecting the normal production of the gas well. The gas wells with serious conditions mentioned above were selected to analyze the quality of single well produced water and the composition of blockage and core. Combined with the XRD analysis results of the cuttings, the long-term leaching experiments on the cuttings in different simulated solutions were carried out to study the sources of scaled ions in the gas wells. The experimental results showed that the extracted water from SD6-1 had high salinity and high content of scale ions Ca2+, Ba2+ and Sr2+;the main component of blockage is the acid insoluble strontium sulfate (barium) scale, and contains a small amount of corrosion products. The easily scalable Ca2+、Mg2+、Ba2+ and Sr2+ produced from the dissolution of the core in the formation water or working fluids, especially the acid erosion dissolves. According to the scaling mechanism, two kinds of Sr/Ba scale inhibitor were selected. The results showed that the barium II scale inhibitor performance is relatively good, and at the concentration of 40 mg/L, and the scale inhibition rate was more than 95%. The clogging of a single well can be reduced by adding a scale inhibitor.

Analysis on Casing Size and Steel Grade and Application in High-Temperature High-Pressure Gas Wells

2013 ◽  
Vol 703 ◽  
pp. 143-146
Author(s):  
Ling Feng Li
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Natural Gas ◽  
Gas Production ◽  
Steel Grade ◽  
Production Engineering ◽  
Gas Wells ◽  
Gas Well ◽  
Size Series ◽  
High Temperature High Pressure

Analysis on casing size and steel grade and application in high-temperature high-pressure gas wells are important in natural gas production engineering. This paper presents the standard casing size series, casing steel grade standard and code, types of casing steel grade, main problems in high-temperature high-pressure gas wells, using casing material suitable as solving means for high-temperature high-pressure gas well and application. For application, the study above is good and easy for on-the-spot application.

scholarly journals Tight carbonate gas well deliverability evaluation and reasonable production proration analysis

2021 ◽  
Author(s):  
Jiang Li ◽  
Xianchao Chen ◽  
Ping Gao ◽  
Jingchao Zhou
Keyword(s):  
Numerical Model ◽  
Stress Sensitivity ◽  
Gas Production ◽  
Productivity Index ◽  
Dual Porosity ◽  
Gas Reservoirs ◽  
Gas Well ◽  
Well Production ◽  
Tight Carbonate ◽  
Single Well

AbstractIt is very important to accurately predict the gas well productivity and reasonably allocate the gas production at the early development stage of gas reservoirs. However, both the non-Darcy and stress sensitivity effects have not been investigated in dual-porosity model of tight carbonate gas reservoirs. This paper proposed a new dual-porosity binomial deliverability model and single-well production proration numerical model, which consider the effects of non-Darcy and stress sensitivity. The field gas well deliverability tests data validated the accuracy of the new analytical model, which is a very helpful deliverability method when lacking deliverability test. A geological model was built on the results of the well log, well testing, and well production analysis. Then, a reasonable production proration analysis was conducted based on history matched single-well numerical model. The gas productivity index curve and production–prediction of MX22 several simulation cases were adopted to analyze the reasonable production proration. The results indicate that 1/6 may be suitable for high productivity gas well proration. In addition, the absolute open flow rate from the numerical simulation is higher than that from the new deliverability equation, which also shows that the pressure transient analysis sometimes has some deviation in formation property prediction. It is suggested comprehensively utilizing the analytical binomial model and the single-well numerical model in tight carbonate gas well deliverability evaluation.

A Pumping System to Enhance Production From Gas Wells

2002 ◽  
Author(s):  
J. J. Rudolf ◽  
T. R. Heidrick ◽  
B. A. Fleck ◽  
R. K. Ridley ◽  
V. S. V. Rajan
Keyword(s):  
Mathematical Model ◽  
Current Model ◽  
Gas Production ◽  
Area Ratio ◽  
Gas Pressure ◽  
Reservoir Pressure ◽  
Gas Wells ◽  
Two Phase ◽  
Efficient Manner ◽  
Gas Well

A new pumping technology has been developed and patented by the Alberta Research Council [1–3] to address the problem of liquid loading in natural gas wells at low, depleted pressures. This technology consists of a pump installed at the bottom of the well bore that is driven by the reservoir gas pressure to bring the produced liquids to the surface as they accumulate thereby improving gas production from shallow gas wells. The above pump concept has been investigated in two stages of research. In the first stage, a mathematical model was developed to estimate the minimum reservoir pressure required to prevent liquid build up in a gas well with either: • the reservoir pressure (and flow) itself carrying the produced liquids to the surface in a two-phase flow, or • the reservoir gas pressure powering a pumping device to carry the produced liquids to the surface in the most efficient manner possible. The objective of the second stage of this investigation was to look at the feasibility of using a reciprocating pump powered by gas pressure. In particular, the effect of the pump Area Ratio (ratio of the area being pushed by the gas to the area pushing the liquid) on the use of reservoir gas pressure was investigated. There are approximately 70,000 flowing gas wells in Western Canada and these gas wells were categorized by depth and production rate. From this list of gas wells, a typical well was chosen and its production data and well characteristics were incorporated into the mathematical model. The model was tested in both the above-mentioned investigations and the results show that there is a significant increase in the operating range when the reservoir pressure is used more efficiently to produce gas from the well. It was determined that higher pump area ratios lead to a more efficient use of reservoir pressure and for the gas well investigated in this study, an optimum area ratio of 40 was identified as the best design. The concept of multistage pumping was also investigated. The results presented are the basis for experiments presently being designed that will validate the current model of the system and allow for possible improvements.

A Pumping System to Enhance Production From Gas Wells

2004 ◽  
Vol 126 (4) ◽  
pp. 311-319 ◽  
Author(s):  
Jeffrey J. Rudolf ◽  
Ted R. Heidrick ◽  
Brian A. Fleck ◽  
Rodney K. Ridley ◽  
Raj V. S. V. Rajan
Keyword(s):  
Mathematical Model ◽  
Current Model ◽  
Gas Production ◽  
Area Ratio ◽  
Gas Pressure ◽  
Reservoir Pressure ◽  
Gas Wells ◽  
Efficient Manner ◽  
Gas Well ◽  
Pumping System

A new pumping concept has been developed and patented by the Alberta Research Council to address the problem of liquid loading in natural gas wells at low, depleted pressures. This concept consists of a pump installed at the bottom of the wellbore that is driven by the reservoir gas pressure to bring the produced liquids to the surface as they accumulate thereby improving gas production from shallow gas wells. The above pump concept has been investigated in two stages of research. In the first stage, a mathematical model was developed to estimate the minimum reservoir pressure required to prevent liquid build up in a gas well with either: 1) the reservoir pressure (and flow) itself carrying the produced liquids to the surface in a two-phase flow or 2) the reservoir gas pressure powering a pumping system to carry the produced liquids to the surface in the most efficient manner possible. The objective of the second stage of this investigation was to look at the feasibility of using a reciprocating pump powered by gas pressure. In particular, the effect of the pump Area Ratio (ratio of the area being pushed by the gas to the area pushing the liquid) on the use of reservoir gas pressure was investigated. There are approximately 75,000 flowing gas wells in western Canada and these gas wells were categorized by depth and production rate. From this list of gas wells, a typical well was chosen and its production data and well characteristics were incorporated into the mathematical model. The model was tested in both the above-mentioned investigations and the results show that there is a significant increase in the operating range when the reservoir pressure is used more efficiently to produce gas from the well. It was determined that higher pump-area ratios lead to a more efficient use of reservoir pressure and for the gas well investigated in this study, an optimum area ratio of 40 was identified as the best design. The concept of multistage pumping was also investigated. The results presented are the basis for experiments presently being designed that will validate the current model of the system and allow for possible improvements.

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