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.

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.

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.

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%.

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.

Optimum Design Parameters for Reciprocating Pumps Used in Natural Gas Wells

2005 ◽  
Vol 127 (4) ◽  
pp. 285-292 ◽  
Author(s):  
Jeffrey J. Rudolf ◽  
Ted R. Heidrick ◽  
Brian A. Fleck ◽  
V. S. V. Rajan
Keyword(s):  
Optimum Design ◽  
Field Testing ◽  
Design Parameters ◽  
Gas Wells ◽  
Pump System ◽  
Gas Well ◽  
Pumping System ◽  
Liquid Phases ◽  
Reciprocating Pump ◽  
Direct Acting

Experimental and theoretical investigation of a recently patented down-hole direct-acting reciprocating pump system is presented. The technology, (US Patent No. 5,860,795) consists of operating a gas well with gas and liquid phases being produced separately by using the gas phase to power a pump to bring the liquid phase to the surface. This would increase the duration of profitability of many gas wells in North America. Experiments and modeling were used to determine optimum design parameters to maintain flow at a minimum reservoir pressure; an optimum area ratio for the gas/liquid pistons is approximately 40. The effect of friction in the pumping system was predicted to have a small effect on this optimum design. The results of this investigation will now be used to design and construct a prototype for field testing.

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.

scholarly journals Performance Analysis of Gas Wells Based on the Conventional Decline Parameters and the Flow Integral Equation

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-24
Author(s):  
Lixia Zhang ◽  
Yong Li ◽  
Xinmin Song ◽  
Mingxian Wang ◽  
Yang Yu ◽  
...  
Keyword(s):  
Performance Analysis ◽  
Balance Equation ◽  
Integral Method ◽  
Material Balance ◽  
Gas Production ◽  
Parameter Method ◽  
Reservoir Pressure ◽  
Material Balance Equation ◽  
Gas Wells ◽  
Decline Rate

The estimation of reserves and performance prediction are two vital tasks for the development of gas reservoirs where the evaluation of gas in place or well-controlled reserves, as the foundation of the performance analysis of gas wells, turns to be exceedingly significant. Advanced production data analysis or modern rate transient analysis (RTA) methods mainly depend on the iterative calculations of material balance quasitime ( t ca ) and type curve fitting, the essence of which is to update the average reservoir pressure data time and again. The traditional Arps’ decline models are of empirical nature despite the convenience and applicability to the constant bottomhole pressure (BHP) condition. In order to avoid the implicit iteration, this paper develops an explicit method for estimating the average reservoir pressure on the basis of dynamic material balance equation (DMBE), termed “flow integral method,” which can be applied to various gas production systems under boundary-dominated flow (BDF). Based on the flow integral method and the decline parameter evaluation, we employ the hyperbolic decline model to model the gas well performance at a constant BHP. The analytical formulations of decline rate and decline exponent are deduced from the DMBE and the static material balance equation (SMBE) considering the elastic compressibilities of rock pore and bound water. The resulting decline parameter method for explicit estimation of gas reserves boasts a solid and rigorous theory foundation that production rate, decline rate, and average reservoir pressure profiles have reference to each other, and its implementation steps are explained in the paper. The SMBE can, combined with the estimated pressure profile by the flow integral method, also be used to determine gas reserves which is not limited to the constant-BHP condition and can calibrate the estimates of the decline parameter method. The proposed methods are proven effective and reliable with several numerical cases at different BHPs and a field example.

scholarly journals A new model for calculating the critical fluid carrying rate in inclined Wells

2020 ◽  
Vol 213 ◽  
pp. 03009
Author(s):  
Quan Hua Huang ◽  
Xing Yu Lin
Keyword(s):  
Gas Production ◽  
Production Plan ◽  
Droplet Model ◽  
Gas Wells ◽  
Gas Reservoir ◽  
Spherical Cap ◽  
Gas Well ◽  
Spherical Droplet ◽  
Application Range ◽  
Wide Range

In the preparation of gas production plan and the study of gas well proration we often judge the fluid carrying capacity of gas well by the critical fluid carrying rate of the gas well, and then adjust the production plan. At present, spherical droplet model and ellipsoidal droplet model are often used to calculate the fluid flow in gas Wells, but the spherical cap droplet model has not been concerned by relevant scholars. Therefore, we studied the application range of spherical cap droplet model, established relevant mechanical expressions, and finally obtained the formula for calculating the minimum critical liquid carrying rate of spherical cap droplet model. The results show that the spherical cap droplet model cannot be ignored in the conventional droplet model and has a wide range of applications. At the same time, the model is validated by combining with gas Wells of H gas reservoir, and the model has good applicability.

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