Transient Simulation of Wellbore Pressure and Temperature During Gas-Well Testing

2014 ◽  
Vol 136 (3) ◽  
Author(s):  
Tong Liu ◽  
Hai-quan Zhong ◽  
Ying-chuan Li
Keyword(s):  
State Equation ◽  
Transfer Model ◽  
Pressure Curve ◽  
Well Testing ◽  
Gas Field ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Wellbore Pressure ◽  
Abnormal Phenomenon ◽  
The Difference

An abnormal phenomenon may occur during gas-well testing: the wellhead pressure initially rises and then drops when shutting-in a well; the wellhead pressure initially drops and then rises when opening a well. To determine why and how this phenomenon occurs, a transient nonisothermal wellbore flow model for gas-well testing is developed. Governing equations are based on depth- and time-dependent mass, momentum equations, and the gas state equation. Temperature is predicted using the unsteady-state heat transfer model of Hasan. Boundary conditions include the restriction of formation inflow and wellhead throttling to the flow. The difference equations are established based on the implicit central finite difference method. The model can simulate the influences of temperature and flux (mass velocity). The model also considers the effects of formation inflow and surface throttling on the system. The results indicate wellhead pressure under flowing temperature is higher than that under static temperature, thus causing the abnormal phenomenon. A larger pressure difference makes the abnormal phenomenon more significant. Without considering temperature variation, simulated wellhead pressure would not exhibit the abnormity. Without considering flux variation, simulated pressure curve is not smooth. A new model has thus been validated using a gas field example.

A Novel Approach to Evaluate Deliverability of Gas Wells with Pressure Fluctuation

2021 ◽  
Author(s):  
Yongbin Zhang ◽  
Xiongwei Sun ◽  
Xiaojia Bai ◽  
Wei Jia ◽  
Bo Zhu ◽  
...  
Keyword(s):  
Pressure Fluctuation ◽  
Evaluation Method ◽  
Dynamic Change ◽  
Field Studies ◽  
Well Testing ◽  
Wax Deposition ◽  
Gas Well ◽  
New Approach ◽  
Wellhead Pressure ◽  
Geological Conditions

Abstract Majority of gas fields in Tarim Basin are HPHT (high-pressure/high temperature) reservoirs with buried depth more than 5000m. The special geological conditions made it a challenge for underground well testing due to safety issues. Additionally, wellhead pressure fluctuation is widely existed both from geological and engineering factors, including sand production, well casing integrity problems, contamination of downhole fracturing fluid and wax deposition in wellbore etc. Traditional deliverability evaluation method which relies on underground well testing is greatly limited as it is not capable of reflecting the dynamic change of gas well deliverability due to abnormal wellhead pressure fluctuation. In this study, a new approach is proposed to evaluate the deliverability of these kind of wells using dynamic data from wellheads. An apparent and a potential deliverability curves are based on binomial deliverability equation are established individually according to whether the additional skin caused by wellbore blockage is taken into consideration. The variation characteristic of gas well deliverability is obtained by comparison of potential and apparent absolute open flow. Finally, field studies of Dina abnormal wells are performed to verify the accuracy of the method. Deliverability analysis show that the new approach has a great advantage in evaluating the production potential of wells with pressure fluctuation, and furtherly provides the criteria for wellbore management.

Real-Time Estimation and Management of Hydrate Plugging Risk During Deepwater Gas Well Testing

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3250-3264 ◽  
Author(s):  
Jianbo Zhang ◽  
Zhiyuan Wang ◽  
Wenguang Duan ◽  
Weiqi Fu ◽  
Baojiang Sun ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Real Time ◽  
Hydrate Formation ◽  
Dynamic Effect ◽  
Time Estimation ◽  
Gas Production ◽  
Well Testing ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Real Time Estimation

Summary Hydrate formation and deposition are usually encountered during deepwater gas well testing, and if hydrates are not detected and managed in time, a plugging accident can easily occur. In this study, we demonstrate a method for estimating and managing the risk of hydrate plugging in real time during the testing process. The method includes the following steps: predicting the hydrate stability region, calculating the hydrate formation and deposition behaviors, analyzing the effect of the hydrate behaviors on variations in wellhead pressure, monitoring the variations in wellhead pressure and estimating the hydrate plugging risk in real time, and managing the risk in real time. An improved pressure-drop calculation model is established to calculate the pressure drop in annular flows with hydrate behaviors, and it considers the dynamic effect of hydrate behavior on fluid flow and surface roughness. The pressure drops calculated at different times agree well with experimental and field data. A case study is conducted to investigate the applicability of the proposed method, and results show that with the continued formation and deposition of hydrates, both the effective inner diameter of the tubing and the wellhead pressure decrease accordingly. When the wellhead pressure decreases to a critical safety value under a given gas production rate, a hydrate inhibitor must be injected into the tubing to reduce the severity of hydrate plugging. It is also necessary to conduct real-time monitoring of variations in wellhead pressure to guarantee that the risk of hydrate plugging is within a safe range. This method enables the real-time estimation and management of hydrate plugging during the testing process, and it can provide a basis for the safe and efficient testing of deepwater gas wells.

Numerical Simulation of Pressurization Scheme of Gas Well in Jingbian Gas Field

2013 ◽  
Vol 830 ◽  
pp. 444-447
Author(s):  
Bao Chao Du ◽  
Ling Yang
Keyword(s):  
Numerical Simulation ◽  
Three Dimensional ◽  
Simulation Method ◽  
Test Method ◽  
Pipe Network ◽  
Gas Reservoir ◽  
Gas Field ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Orthogonal Test Method

With the exploitation of Jingbian Gas Field for decades, the formation energy gradually decreasing, and the wellhead pressure of some gas wells were found approaching to the pressure of gathering pipe network. Furthermore, some wellhead pressure can not make the produced natural gas get into the gathering pipe network. S well block of Jingbian Gas Field was set as the research object, applied numerical simulation method to create a new three dimensional geological model for gas reservoir of S well block, and then matched the reserves of gas reservoir and productivity parameters of gas well; applied the orthogonal test method design a variety of charging scheme and simulated every scheme; finally, decided an applicative pressurization scheme for gas well of S well block in Jingbian Gas Field.

First Successful Application of Casing in Casing CiC Refracturing Treatment in Shale Gas Well in China: Case Study

2021 ◽  
Author(s):  
Yaowen Liu ◽  
Yuanzhao Li ◽  
Chi Zhang ◽  
Yue Ming ◽  
Jialin Xiao ◽  
...  
Keyword(s):  
Shale Gas ◽  
High Performance ◽  
Fracture Initiation ◽  
Successful Implementation ◽  
Treatment Rate ◽  
Gas Field ◽  
Gas Well ◽  
Wellhead Pressure ◽  
The Impact

Abstract With active hydraulic fracturing performed since 2012, the Fuling shale gas field in China is one of the largest shale gas fields outside of North America. Recently, a Casing-in-Casing (CiC) refracturing treatment was successfully implemented, resulting in production beyond expectations. This was the first successful application of a CiC refracturing treatment in a horizontal shale gas well in this region, thus providing a new option for refracturing horizontal wells in China. Bullheading diversion refracturing with diverting balls was previously attempted in this field with high initial production observed; however, production was inconsistent and quickly declined. Therefore, the operator decided to attempt a CiC refracturing method in an understimulated candidate well. This involved installing and cementing 3.5-in. casing in 5.5-in. casing to effectively isolate the perforations, which enabled plugging and perforating operations in the reconstructed wellbore for an effective refracturing treatment. A customized refracturing design integrated the production profile, residual recoverable reserves, and the specific 5.5- × 3.5-in. reconstructed wellbore limitation. The length of the 3.5-in. casing was optimized to be as short as possible but still cover the original perforations, and high-performance slickwater was used to reduce pipe friction, thus increasing the treatment rate. An engineered breakdown approach was employed for improved fracture initiation. Additionally, more clusters were added between the original clusters and, based on production profile results, some of the original understimulated clusters with little proppant placement were reperforated. To overcome the impact of depleted fractures, a self-degradable particulate diverting agent was used to propagate new fractures, allowing access to new rock to increase total reserve recovery. The treatment in the reconstructed wellbore was successful, with 21 stages fractured in 12 days, achieving 100% placement of the designed proppant and fluid. A treatment rate of 7 to 12 m3/min from the toe to heel was executed as designed. Test production of 183,800 m3/D was also achieved with a recovery rate of 88.1%. Production has remained consistent and wellhead pressure has remained steady at a high level throughout the first two months of production. CiC refracturing technology helps overcome common disadvantages experienced with traditional refracturing techniques, such as poorly placed proppant and fluid and inconsistent production. CiC refracturing not only allows exploitation of bypassed reserves from original fractures, but also allows precise stimulation of new rock to obtain the highest reserve recovery. The successful implementation of this case study illustrates the reliability of CiC refracturing technology and provides valuable experience to be used during future regional horizontal well refracturing.

Study of dynamic pressure on the packer for deep-water perforation

Open Physics ◽  
2021 ◽  
Vol 19 (1) ◽  
pp. 215-223
Author(s):  
Hao Huang ◽  
Qiao Deng ◽  
Hui Zhang
Keyword(s):  
Deep Water ◽  
Peak Pressure ◽  
Orthogonal Design ◽  
Dynamic Pressure ◽  
Three Dimensional ◽  
Calculation Model ◽  
Well Testing ◽  
Technical Problems ◽  
Wellbore Pressure ◽  
Three Dimensional Finite Element

Abstract The packer is one of the most important tools in deep-water perforation combined well testing, and its safety directly determines the success of perforation test operations. The study of dynamic perforating pressure on the packer is one of the key technical problems in the production of deep-water wells. However, there are few studies on the safety of packers with shock loads. In this article, the three-dimensional finite element models of downhole perforation have been established, and a series of numerical simulations are carried out by using orthogonal design. The relationship between the perforating peak pressure on the packer with the factors such as perforating charge quantity, wellbore pressure, perforating explosion volume, formation pressure, and elastic modulus is established. Meanwhile, the database is established based on the results of numerical simulation, and the calculation model of peak pressure on the packer during perforating is obtained by considering the reflection and transmission of shock waves on the packer. The results of this study have been applied in the field case of deep-water well, and the safety optimization program for deep-water downhole perforation safety has been put forward. This study provides important theoretical guidance for the safety of the packer during deep-water perforating.

scholarly journals Long-Term Observations of Microwave Brightness Temperatures over a Metropolitan Area: Comparison of Radiometric Data and Spectra Simulated with the Use of Radiosonde Measurements

2021 ◽  
Vol 13 (11) ◽  
pp. 2061
Author(s):  
Mikhail V. Belikovich ◽  
Mikhail Yu. Kulikov ◽  
Dmitry S. Makarov ◽  
Natalya K. Skalyga ◽  
Vitaly G. Ryskin ◽  
...  
Keyword(s):  
Radiative Transfer ◽  
Elevation Angle ◽  
Radiative Transfer Model ◽  
Transfer Model ◽  
Systematic Bias ◽  
Tropospheric Temperature ◽  
Absorption Model ◽  
60 Ghz ◽  
Error Budget ◽  
The Difference

Ground-based microwave radiometers are increasingly used in operational meteorology and nowcasting. These instruments continuously measure the spectra of downwelling atmospheric radiation in the range 20–60 GHz used for the retrieval of tropospheric temperature and water vapor profiles. Spectroscopic uncertainty is an important part of the retrieval error budget, as it leads to systematic bias. In this study, we analyze the difference between observed and simulated microwave spectra obtained from more than four years of microwave and radiosonde observations over Nizhny Novgorod (56.2° N, 44° E). We focus on zenith-measured and elevation-scanning data in clear-sky conditions. The simulated spectra are calculated by a radiative transfer model with the use of radiosonde profiles and different absorption models, corresponding to the latest spectroscopy research. In the case of zenith-measurements, we found a systematic bias (up to ~2 K) of simulated spectra at 51–54 GHz. The sign of bias depends on the absorption model. A thorough investigation of the error budget points to a spectroscopic nature of the observed differences. The dependence of the results on the elevation angle and absorption model can be explained by the basic properties of radiative transfer and by cloud contamination at elevation angles.

Analysis Methods of Bottom Pressure for Fractured-Vuggy Reservoir

2011 ◽  
Vol 291-294 ◽  
pp. 3449-3453
Author(s):  
Bao Hua Chang ◽  
Wei Xiong ◽  
Shu Sheng Gao
Keyword(s):  
Bottom Pressure ◽  
Simple Method ◽  
Wellhead Pressure ◽  
Analysis Methods ◽  
Wellbore Pressure

It’s difficult to measure bottom pressure in the fractured-vuggy reservoir, and measuring cost is usually high; In this paper, using the modified Beggs-Brill method, the variety of wellbore pressure has been calculated and analyzed. Results show that the variety of wellhead pressure is consistent with that of bottom pressure, and the variety of wellhead pressure is greater than that of bottom pressure. Thereby a simple method of predicting bottom pressure through wellhead pressure is established. Through example calculation, it’s confirmed that this method has a certain reliability and practicability.

A Study of Downhole Drillable Pulsing Cementing Device with Low Frequency Self-Excited Hydraulic Oscillation and its Field Application

2012 ◽  
Vol 450-451 ◽  
pp. 1536-1539
Author(s):  
Cui Ping Nie ◽  
Deng Sheng Ye
Keyword(s):  
Setting Time ◽  
Low Frequency ◽  
Field Application ◽  
Displacement Efficiency ◽  
Cement Slurry ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Gas Well ◽  
Hydraulic Oscillation ◽  
Injection Technology

Abstract: Usually we pay more attention on how to improve gas well cementing quality in engineering design and field operations, and there are so many studies on cement agents but few researches on cement slurry injection technology. The field practice proved that conventional cementing technology can not ensure the cementing quality especially in gas well and some abnormal pressure wells. Most of the study is concentrated on cement agents and some cementing aspects such as wellbore condition, casing centralization etc. All the factors analysis on cementing quality has pointed out that a combination of good agents and suitable measurements can improve cementing quality effectively. The essential factor in cementing is to enhance the displacement efficiency, but normal hole condition and casing centralization are the fundamental for cementing only. Pulsing cementing is the technology that it can improve the displacement efficiency especially in reservoir well interval, also it can shorten the period from initial to ultimate setting time for cement slurry or improve thickening characteristics, and then to inhibit the potential gas or water channeling. Based on systematically research, aiming at improving in 7″ liner cementing, where there are multi gas reservoirs in long interval in SiChuan special gas field, well was completed with upper 7″ liner and down lower 5″ liner, poor cementing bonding before this time. So we stressed on the study of a downhole low frequency self-excited hydraulic oscillation pulsing cementing drillable device and its application, its successful field utilization proved that it is an innovative tool, and it can improve cementing quality obviously.

scholarly journals Evaluation of natural gas production optimization in Kailashtila gas field in Bangladesh using decline curve analysis method

2015 ◽  
Vol 50 (1) ◽  
pp. 29-38 ◽  
Author(s):  
MS Shah ◽  
HMZ Hossain
Keyword(s):  
Production System ◽  
Gas Production ◽  
Curve Analysis ◽  
Production Optimization ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Wellhead Pressure ◽  
Decline Curve Analysis ◽  
Decline Curve ◽  
Overall Performance

Decline curve analysis of well no KTL-04 from the Kailashtila gas field in northeastern Bangladesh has been examined to identify their natural gas production optimization. KTL-04 is one of the major gas producing well of Kailashtila gas field which producing 16.00 mmscfd. Conventional gas production methods depend on enormous computational efforts since production systems from reservoir to a gathering point. The overall performance of a gas production system is determined by flow rate which is involved with system or wellbore components, reservoir pressure, separator pressure and wellhead pressure. Nodal analysis technique is used to performed gas production optimization of the overall performance of the production system. F.A.S.T. Virtu Well™ analysis suggested that declining reservoir pressure 3346.8, 3299.5, 3285.6 and 3269.3 psi(a) while signifying wellhead pressure with no changing of tubing diameter and skin factor thus daily gas production capacity is optimized to 19.637, 24.198, 25.469, and 26.922 mmscfd, respectively.Bangladesh J. Sci. Ind. Res. 50(1), 29-38, 2015

Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

2021 ◽  
Author(s):  
Mohd Hafizi Ariffin ◽  
Muhammad Idraki M Khalil ◽  
Abdullah M Razali ◽  
M Iman Mostaffa
Keyword(s):  
New Technology ◽  
Lessons Learned ◽  
Oil Fields ◽  
Submersible Pump ◽  
Large Space ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

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