scholarly journals Identification and Characterization of High Permeability Zones Using Conventional Logging and Production Logging Data: A Case Study of Kela 2 Gas Field

2021 ◽  
Author(s):  
Yongzhong Zhang ◽  
Hualin Liu ◽  
Weigang Huang ◽  
Zhaolong Liu ◽  
Baohua Chang
Keyword(s):  
Gas Flow ◽  
Computer Modelling ◽  
High Permeability ◽  
Gas Reservoir ◽  
Gas Field ◽  
Field Development ◽  
Water Breakthrough ◽  
Stable Production ◽  
Permeability Distribution

High permeability zones in the water-drive gas reservoir tend to act as dominant channels for formation water to invade into gas reservoir from the aquifer. The presence of high permeability zones results in uneven water flow front in reservoir and early water breakthrough in gas well, which seriously affects the gas field development. In this paper, conventional logging and production logging data are used to identify and characterize high permeability zones, so as to guide the optimization of development plan of Kela 2 gas field. A method to determine the lower limit of high permeability zones by using cumulative frequency curve of permeability distribution is proposed, and high permeability zones of 21 wells are identified. These high permeability zones account for 10–15% of the effective reservoir thickness in single wells, and they are mainly distributed in the middle of the Bashijiqike (K1bs) Formation (i.e., K1bs12, K1bs21 and K1bs22). The analysis of production logging data shows that the effective gas producing intervals only account for 29.2% of the total number of test intervals, most of which are related to high permeability zones. Further study shows that the high gas flow from the high permeability zones dominates the wellbore production profile, and the gas in low permeability zones flows vertically to the high permeability zones and horizontally to wellbore through these zones. Through the analysis of production profiles over the years and computer modelling, it is confirmed that water channelling occurred in some gas wells at the depth where the high permeability zones are located, which leads to a significant decline in production of these wells. Based on the study of distribution and behaviour characteristics of the high permeability zones, two suggestions on controlling inhomogeneous water invasion are put forward to realize the sustainable and stable production of the gas field.

scholarly journals Petro physical parameter studies for characterization of gas reservoir of Narsingdi gas field, Bangladesh

2014 ◽  
Vol 2 (2) ◽  
Author(s):  
Abu Reza Md. Towfiqul Islam ◽  
Md. Islam ◽  
Anjum Tasnuva ◽  
Raman Biswas ◽  
Khurshida Jahan
Keyword(s):  
Physical Parameter ◽  
Gas Reservoir ◽  
Gas Field

Rational Production Proration of Gas Wells in Unconsolidated Sandstone Gas Reservoir

2011 ◽  
Vol 121-126 ◽  
pp. 1249-1253
Author(s):  
Guo Yun Wu ◽  
Jiao Li
Keyword(s):  
Well Test ◽  
Gas Reservoir ◽  
Gas Recovery ◽  
Water Influx ◽  
Water Breakthrough ◽  
Stable Production ◽  
Single Well ◽  
Rational Production ◽  
Set Up

Multi-layered unconsolidated sandstone gas reservoir is featured by unconsolidated lithology, interbeded gas-water zones and active edge water. Irrational production proration will lead to water breakthrough and sand inflow(AOF) is already incompetent in solving problems nowadays. Based on multipoint well test deliverability analysis, production data dynamic analysis, single well controlled reserves and critical situation of inflow calculation, and combining the calculation of minimum liquid hold-up gas rate an maximum erosion gas rate, meanwhile considering balanced gas recovery factor, balanced pressure drop, safe sand inflow and safe liquid hold-up, the multi-factor production plan has been set up, which is improved and adjusted by integrating water influx performance and years of stable production, through gas reservoir numerical simulation. A scientific and rational production proration pattern particularly for this type of gas reservoir has been determined. The reservoir simulation results of case study show that the water production in gas well can be controlled and the gas reservoir sustained stable production can last more than 1.3 year.

An Approach and Case Study on Determination of the Sulfur Deposition Radius in High Sulfur Gas Reservoir

2014 ◽  
Vol 1073-1076 ◽  
pp. 592-596
Author(s):  
Pei Luo ◽  
Yu Ming Luo ◽  
Kai Ma ◽  
Biao Zhang ◽  
Sha Sha Song
Keyword(s):  
Sulfur Deposition ◽  
Mixed Gas ◽  
Gas Reservoir ◽  
Gas Field ◽  
Gas Well ◽  
Pressure Transient ◽  
Field Development ◽  
Eastern Sichuan Basin

In the process of high sulfur gas field development, the sulfur will separate out from the mixed gas when the pressure near wellbore area drops to a critical pressure of H2S. This will reduce the reservoir porosity greatly and decrease the gas well productivity as well. This paper discusses the characteristics of pressure transient testing plots when sulfur deposition occurs based on the redial composite reservoir model. And introduce an approach to determine the sulfur deposition radius near the wellbore with pressure transient testing interpretation in high sulfur gas reservoir. The method has been applied in some high sulfur gas field in eastern Sichuan Basin. The result shows that the method is simple and practical.

scholarly journals High Temperature (Up to 950 °C) Sensor Based on Micro Taper In-Line Fiber Mach–Zehnder Interferometer

2019 ◽  
Vol 9 (12) ◽  
pp. 2394 ◽  
Author(s):  
Yun-Cheng Liao ◽  
Bin Liu ◽  
Juan Liu ◽  
Sheng-Peng Wan ◽  
Xing-Dao He ◽  
...  
Keyword(s):  
High Temperature ◽  
Gas Flow ◽  
Zehnder Interferometer ◽  
Large Temperature ◽  
Probe Type ◽  
Gas Field ◽  
Linear Temperature ◽  
Field Development ◽  
Type Fiber ◽  
Mach Zehnder Interferometer

A high temperature (up to 950 °C) sensor was proposed and demonstrated based on a micro taper in-line fiber Mach–Zehnder interferometer (MZI) structure. The fiber MZI structure comprises a single mode fiber (SMF) with two micro tapers along its longitudinal direction. An annealing at 1000 °C was applied to the fiber sensor to stabilize the temperature measurement. The experimental results showed that the sensitivity was 0.114 nm/°C and 0.116 nm/°C for the heating and cooling cycles, respectively, and, after two days, the sensor still had a sensitivity of 0.11 nm/°C, showing a good stability of the sensor. A probe-type fiber MZI was designed by cutting the sandwiched SMF, which has good linear temperature responses of 0.113 nm/°C over a large temperature range from 89 to 950 °C. The probe-type fiber MZI temperature sensor was independent to the surrounding refractive index (RI) and immune to strain. The developed sensor has a wide application prospect in the fields of high temperature hot gas flow, as well as oil and gas field development.

Determing the Reasonable Single-Well Proration in Gas Reservoir by the Method of Dynamic Production

2012 ◽  
Vol 204-208 ◽  
pp. 297-302
Author(s):  
Kui Zhang ◽  
Hai Tao Li ◽  
Yang Fan Zhou ◽  
Ai Hua Li
Keyword(s):  
Low Permeability ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Gas Field ◽  
Gas Well ◽  
High Productivity ◽  
Well Production ◽  
Stable Production ◽  
Single Well

Low permeability, low abundance, water-bearing gas reservoirs are widely distributed in China, and their reserves constitute 85% of all kinds of reservoirs in current. It has important realistic meanings to develop them. Determining of reasonable gas well production is the prerequisite to achieving long-term high productivity and stable production. This paper takes Shanggu gas field at Sulige Gas Field for example, respectively from the dynamic data analogy methods, the pressure drop rate statistical methods, gas curve methods, production system nodal analysis methods, and studied the reasonable capacity of the low permeability gas reservoir. Through comprehensive analysis，the comprehensive technical indexes about single well reasonable production was determined.

LONGTOM—CONFIRMATION OF A NEW PLAY IN OFFSHORE GIPPSLAND

2007 ◽  
Vol 47 (1) ◽  
pp. 91
Author(s):  
K.P. Lanigan ◽  
G. Bunn ◽  
J. Rindschwentner
Keyword(s):  
Gas Flow ◽  
Seismic Inversion ◽  
Production Test ◽  
Interactive Approach ◽  
New Production ◽  
Gas Field ◽  
Field Development ◽  
History Of ◽  
Gippsland Basin ◽  
Inversion Techniques

The Longtom gas field was discovered in 1995, when the Longtom–1/ST1 wildcat well in the northern part of the offshore Gippsland Basin encountered dry gas in tight sandstones towards the base of the Latrobe Group, in what is now called the Admiral Formation of the Emperor Subgroup. In 2004 the Longtom–2/ST1 exploration well confirmed significant vertical and lateral extension of these prospective gas sands, and also provided very encouraging production test and core data. The recent Longtom–3 wells have demonstrated the viability of this new play by confirming significant lateral continuity of the thicker gas sands and demonstrating high gas flow rates. The history of the field’s discovery and appraisal illustrates how a multi-disciplinary and interactive approach, guided by innovative seismic inversion techniques and real-time petrophysical data, resulted in the successful planning and execution of the Longtom–3 drilling and evaluation program. The results of the wells and the outline of the field development plan illustrate how Longtom represents new production potential in this mature basin.

scholarly journals Comprehensive Research of Scaling Prediction for Gas Reservoir Fluid considering Phase State

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-13
Author(s):  
Heng Zheng ◽  
Chunsheng Pu
Keyword(s):  
Phase Change ◽  
Phase State ◽  
Inorganic Salt ◽  
Fluid Phase ◽  
Formation Water ◽  
Equilibrium System ◽  
Gas Reservoir ◽  
Gas Field ◽  
Average Deviation ◽  
Field Development

During the exploitation of a gas reservoir containing water, the scaling problem is usually affecting the gas production in gas wells. Although the scale formation that occurs during oil field development is quite different from the aforementioned gas field, the phase behavior plays a pivotal role in the formation of inorganic scale in gas field development. It is a well-known fact that there is no device that can directly measure the extent of scaling formation in a high-temperature and high-pressure reservoir. At the same time, the commonly applied scaling prediction method does not account for the fluid phase state. In this work, the scaling condition and alteration in controlling parameters in an actual gas reservoir were studied by self-developed high-temperature and high-pressure formation fluid equipments. From thermodynamics, a new scaling prediction model for the multiphase equilibrium of gas reservoir fluid is proposed that considers gas, liquid hydrocarbon, formation water, and inorganic salt scale. For the complexity of the direct solution for a phase equilibrium system with a chemical reaction, a simplified method for calculating the phase change and chemical equilibrium in a multiphase equilibrium system with chemical reactions is proposed based on the conservation of materials and the unification of the physical properties of components. The results show that the predicted value of the model was consistent with the experimental results. The new scaling prediction model considered the influence of the phase state which can accurately predict the change of the fluid phase state and the amount of inorganic salt scaling of actual gas reservoir fluids under the condition of multiphase equilibrium. Moreover, the average deviation of the prediction results is about 3%. The predicted scaling amount of the model without considering the effect of phase change is significantly lower than that of the experimental results. More specifically, the average deviation is around 30%. With the decrease of gas reservoir pressure, formation water evaporation intensifies under the influence of the oil and gas phase state, which leads to the increase of the formation water ion concentration when the influence of the fluid phase change is not considered. Then, the prediction of the inorganic salt scaling will be significantly lower.

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