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.

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.

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%.

Immediate Gas Production from Shale Gas Wells: A Two-Phase Flowback Model

2014 ◽  
Author(s):  
O.A. Adefidipe ◽  
H. Dehghanpour ◽  
C.J. Virues
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Gas Wells ◽  
Two Phase

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 Prediction and analysis of annular pressure caused by temperature effect for HP/HT/HHS and water production gas wells in Sichuan Basin

2021 ◽  
Author(s):  
Cao Pu
Keyword(s):  
Prediction Model ◽  
Temperature Effect ◽  
Sichuan Basin ◽  
Gas Production ◽  
Influential Factors ◽  
Water Production ◽  
Gas Wells ◽  
Production Rates ◽  
Two Phase ◽  
Actual Measurement

AbstractFor the “three-high” gas wells in Sichuan Basin which are often regulated for production rate and shut-in for maintenance, annular pressure by temperature effect is a kind of wellbore safety threat that cannot be ignored. In this work, the wellbore temperature and pressure calculation model of gas–liquid two-phase flow with non-hydrocarbon correction and the prediction model of annular pressure by temperature effect is developed. Moreover, the judgment chart of annular pressure type is established through a large number of simulation calculations with different gas production rates and water production rates. Example calculation shows that whether water production and non-hydrocarbon components are considered in the prediction model has a non-negligible influence on calculation results. The predicted annular pressure is compared with that obtained from the actual measurement showing a good agreement. Meanwhile, the judgment chart realizes the valid determination of annular pressure type for three “three-high” gas wells in Sichuan Basin. Influential factors analysis indicates that reducing the thermal expansion coefficient of annulus fluid, adding the hollow glass spheres or injecting highly compressible protective liquid into the annulus and installing compressible foam material on the inner wall of casing are effective methods to control the annular pressure by temperature effect. To reserve partial annulus space can effectively reduce the annular pressure by temperature effect. For most of “three-high” gas wells in Sichuan Basin, the optimum height of annulus air cavity is 100 m.

scholarly journals OPERATIONS FOR WATER ISOLATION IN CENOMANIAN WELLS

2015 ◽  
pp. 29-31
Author(s):  
E. V. Panikarovski ◽  
V. V. Panikarovski
Keyword(s):  
Gas Production ◽  
Reservoir Pressure ◽  
Gas Wells ◽  
Reservoir Water ◽  
Water Influx

The article considers the issues related with operations aimed at water isolation in Cenomanian wells. The analysis of methods of water isolation jobs including creation of technological screens and hydrophobization of the productive bed was carried out. It is pointed out that in the conditions of gas production decline and the reservoir pressure drawdown some methods can be used designed for prevention of reservoir water influx in the gas wells. These methods are described in the article.

Material Selection of Gas-Well Wellhead Assembly and Application in High-Sulfur Gas-Well

2013 ◽  
Vol 703 ◽  
pp. 135-138
Author(s):  
Ling Feng Li
Keyword(s):  
Corrosion Resistance ◽  
Natural Gas ◽  
Production System ◽  
Material Selection ◽  
Gas Production ◽  
Gas Wells ◽  
Gas Well ◽  
System Life ◽  
Selection Of

For natural gas well, material selection of gas-well wellhead assembly is an important factor of gas production system life. In order to ensure the long-term development of gas wells, this paper mainly introduces the material selection of gas-well wellhead assembly, proposes the optimization idea and technique of gas-well wellhead assembly. By taking W well as an example, this paper optimizes the material selection of gas-well wellhead assembly for W well. For application, the optimal materials of gas-well wellhead assembly in W well have good performance of corrosion resistance.

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.

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