The Impact of High Noncondensible Gas Concentrations on Well Performance Kizildere Geothermal Reservoir, Turkey (original) (raw)
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Change of water saturation in tight sandstone gas reservoirs near wellbores
Natural Gas Industry B, 2018
Tight sandstone gas reservoirs commonly contain water, so liquid loading often appears near wellbores, leading to production decline and even shutdown of gas wells. Therefore, the study on the change of water saturation near wellbores is of great significance to understanding the water production mechanisms of gas wells. In this paper, a set of physical simulation experiment procedures of identifying the change of water saturation near wellbores was designed according to the principle of radial well seepage of gas wells, and the production performance after vertical well fracturing in gas reservoirs was simulated by connecting tight cores with a diameter of 10.5 cm, 3.8 cm and 2.5 cm in series in a descending order of distance. According to the depressurizing production mode of gas wells, tubes with small diameters of 20, 30, 40 and 50 mm were used to simulate gas well tubing to control the gas production rate. And the change of water saturation near wellbore in the process of depletion production and its influencing factors were investigated. Finally, combined with actual data of production wells, the water saturation and water production of gas wells near wellbores and in different zones were calculated at the above four different small diameters of tubes and the changes thereof were also analyzed. The following results were obtained. First, each gas production rate corresponds to a critical water saturation. When the initial water saturation is lower than the critical value, the formation water flowing near the wellbore and in the middle zone can be carried out along with the production of gas and no liquid loading is formed. Second, when the initial water saturation is higher than the critical value, a large amount of formation water migrating from the far-wellbore zones accumulates near the wellbore, and thus liquid loading occurs at the bottom hole. Third, when the initial water saturation is equal to the critical value, the higher the gas production rate is, the more easily liquid loading tends to form near the wellbore. Fourth, for the same water saturation, water production increases and recovery factor decreases with the increase of gas production rate. In conclusion, the cumulative water production chart of a gas well generated by the physical simulation experiment method proposed in this paper agrees well with the water production behavior of the corresponding gas well. The research results are conducive to the effective prediction of gas well water production and can be used as guidance for the reasonable gas well water control.
Processes
Scaling in a hydrothermal type of geothermal well reduces or interrupts the production of geothermal energy. Calcite is one of the most common scales in geothermal wells. The reason for its formation in geothermal production wells is clear. The flowing up of geothermal water causes a change in the pressure and temperature, which results in the escape of CO2 gas from the geothermal water, causing a rise in pH and the supersaturation of CaCO3 in the solution. To predict scaling in a new geothermal well, conditional data for geothermal well simulations are required. It is important to determine what field data are needed and how to obtain them. It is necessary to deal with some parameters that are hard to measure and that have not been described in detail in the existing literature. In this study, a two-phase flow model and a chemical reaction equilibrium model are integrated to simulate the scaling process in production wells. Based on the simulation, a comprehensive and practical app...
A Study of Pressure Variation in Wellbores During Gas Kicks
It is critical to understand the dynamic behavior and consequences of undesired reservoir influxes that triggers well control emergencies. In contrast to liquid kick, gas influx migration in water based mud and solubility in oil based mud represents exceptionally hazardous conditions. Operation delay time would result in a pressure build-up at the surface with increasing risk of fracturing the casing shoe. In this study, critical factors affecting gas bubble rise velocity in a closed wellbore are studied. These factors are influx size, annulus clearance, reservoir pressure, oil/water ratio, drilling fluid density, reservoir temperature, plastic viscosity and yield point. Three different well types (vertical, directional and horizontal), well deviation angle and wellbore configurations are considered. Gas rise velocity and pressure changes at the surface and bottom hole are monitored at different well shut-in periods. A commercial multiphase dynamic well control simulator utilized with a common well configuration. Preliminary results show that higher gas rise velocities and wellbore pressures were experienced as the severity of the encountered conditions increase due to high reservoir pressure as well as the influx size. In comparison to vertical and directional wells, horizontal wellbore trajectory experienced the lowest surface and bottom hole pressures. The average gas rise velocity in WBM was 82.2 ft./min, while in OBM the average gas rise velocity was 31.96 ft./min. In addition, in OBM while the gas was migrating to the surface, wellbore pressure increases then free gas dissolves completely and stays stationary.
Calcite scaling is widely encountered in geothermal wells and it has to be inhibited since it prevents production. As a result of a pressure drop, thermal fluids start to boil and degas of CO 2 while fluids rise in a wellbore. Thermal fluid becomes saturated to calcite as a result of both CO 2 exsolution and concentration increase of calcium and carbonates as a consequence of boiling. When the first gas bubble is formed, CO 2 exsolution affects the ph and also carbonate species. In order to prevent calcite scaling effectively, inhibitor must be injected into the wellbore at a depth below gas breakout point where thermal fluid is still in liquid phase. Thermal fluid transforms from 100% liquid to both liquid and gas phases at the gas breakout depth when the sum of partial pressures of water vapor and non-condensable gases exceed the wellbore pressure under flowing conditions. There are a lot of ways to predict the gas breakout depth in geothermal wellbores. One of them, the easiest b...
SPE 39972 Analysis of Linear Flow in Gas Well Production
qbstract submitted by the author(s). Contents cd the paper, as -fed. * n~~0 M* by Me .%cw@ d Petroleum Engineam and are subject to corr~on by the atithor(s) lle material, as presantad, does not necessarily reflect any position of the Sochty C4Ps4roleum Enginaars, its officers, or members Papers presented ad SPE meetings are subject to publication review by Editorial Commtiees of the Society of Petroleum Engineers Electronic reproduction, distitbution, or storage of any pati of ttws paper for mrnmercial purpasea wthout the wrilten consent of the Scmety of Petroleum Engineers is pmhibifd Permission to reproduce m print is restricted to an abstract of not more than S02 words, illustrations may not ba mpmd l%e abstract must contain conspicuous acknwhdgment C# where and by whom the paper was presented Write Librarian, SPE. PO, 130xS3S93%, Richardson. TX 7S0S3-3.536, U S A , fax 01 -972.9S2-943S
Evaluation of Tight Gas Reservoirs
Tight gas is an important unconventional gas resource. It is also a basin centered gas reservoir which is associated with existing oilfields or bypassed zones and characterized by low in situ permeability of less than 0.6 mili Darcy. This evaluation initially started at San Juan basin in USA. There are about 40,000 tight gas wells producing from 1600 reservoirs in 900 fields whose estimated capacity is 3400 tcf. In India, the Cambay field holds about 413 bcf. amount of tight gas reserves. The layers of Tight Gas are attributed to commingled production and they are often layered and complex. Since the permeability is quite low, the reserves cannot be obtained profitably by vertical wells. As a result mostly horizontal wells and S-shaped wells are used for production of tight gas. Processes like Hydraulic Fracturing and Acidization are used to stimulate the well for better recovery. This technical paper aims at evaluation of tight gas reservoir in order to ameliorate the exploitation through different processes like material balance, volumetric method, transient pressure test, productivity index test and decline curve method along with the modern methods of interpretation of concentration pattern such as detailed Petrography by implementing XRD(X-ray diffraction) and SEM (Scanning Electron Microscope). Elemental Capture Spectroscopy along with Spectral Gamma Logging helps in detecting the distribution within wells. Tight Gas offers maximum recovery rate of 20%.
International Journal of Petroleum and Petrochemical Engineering (IJPPE), 2019
An offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 mD, and porosity distribution for the reservoir varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This work identifies parameters that will contribute to the impact of water coning by observing the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that, locating horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer and less recovery compared to north-south and original wells orientation (northwest-southeast). Varying height of perforation of the well and standoff between 30 m and 40 m will delay water coning and high recovery with more extended plateau length period. The gas recovery was observed to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index (performance of the well). Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery, the high drawdown tendency is observed before water breakthrough time. Horizontal gas wells have a constant horizontal length of 300 m. Increasing tubing head pressure from 40 bar to 100 bar result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning and the gas recovery is reduced by 5%. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19 %, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results, producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact, the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.
An investigation of constant-pressure gas well testing influenced by high-velocity flow
Journal of Petroleum Science and Engineering, 1997
This paper presents the results of a study of transient pressure analysis of gas flow under either constant bottom-hole pressure conditions or the constant wellhead pressure conditions, The effects of formation damage, wellbore storage and high-velocity flow are included in the model. The analysis of simulated well tests showed that the interpretation methods used for liquid flow are generally accurate when the m(p) is used. For these conditions, a graph of l/q D vs. log t D presents gradually lower values of 1.1513 as the value of Pwf decreases: for pressure buildup conditions, a graph of m~(l, At<)/qD(Ata, ,=0) vs. (t,,,+At<)/AtaD shows values of this slope within 1% of the 1.1513 value. However, when high-velocity flow influences constant pressure production tests, the slope can yield errors up to 13%. This upper limit occurs when the formation has a relatively 'high" permeability (around 1 roD) and the rate performance test is affected by high-velocity flow. It was found that pressure buildup tests are superior to rate performance tests because high-velocity flow does not affect the slope of the straight line portion of the buildup curve. Derivative analysis of simulated buildup tests showed that the skin factor is considerably miscalculated when the high-velocity flow effect is significant. This problem could lead to errors in the calculation of the skin factor, s, up to 300%.
Transient pressure analysis of gas wells producing at constant pressure
Journal of Petroleum Science and Engineering, 2003
A comprehensive investigation of the validity of applying the constant-pressure liquid solution to transient rate-decline analysis of gas wells is presented. Pseudo-pressure, non-Darcy flow effects, and formation damage are incorporated in the liquid solution theory to simulate actual real gas flow around the wellbore. The investigation shows that for constant-pressure gas production, the conventional semilog plot of the inverse of the dimensionless rate versus the dimensionless time used for liquid solution must be modified to account for high-velocity flow effects. Especially when reservoir permeability is higher than 1 md and the well test is affected by non-Darcy flow and formation damage.