Performance Evaluation of Gas Production With Consideration of Dynamic Capillary Pressure in Tight Sandstone Reservoirs

2018 ◽  
Vol 141 (2) ◽  
Author(s):  
Leng Tian ◽  
Bo Feng ◽  
Sixu Zheng ◽  
Daihong Gu ◽  
Xiaoxing Ren ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Production Rate ◽  
Water Saturation ◽  
Gas Production ◽  
Tight Sandstone ◽  
Mobile Water ◽  
Dynamic Capillary Pressure ◽  
Irreducible Water Saturation ◽  
Sandstone Reservoirs ◽  
Bottomhole Pressure

In this paper, a pragmatic and consistent framework has been developed and validated to accurately predict reservoir performance in tight sandstone reservoirs by coupling the dynamic capillary pressure with gas production models. Theoretically, the concept of pseudo-mobile water saturation, which is defined as the water saturation between irreducible water saturation and cutoff water saturation, is proposed to couple dynamic capillary pressure and stress-induced permeability to form an equation matrix that is solved by using the implicit pressure and explicit saturations (IMPES) method. Compared with the conventional methods, the newly developed model predicts a lower cumulative gas production but a higher reservoir pressure and a higher flowing bottomhole pressure at the end of the stable period. Physically, a higher gas production rate induces a greater dynamic capillary pressure, while both cutoff water saturation and stress-induced permeability impose a similar impact on the dynamic capillary pressure, though the corresponding degrees are varied. Due to the dynamic capillary pressure, pseudo-mobile water saturation controlled by the displacement pressure drop also affects the gas production. The higher the gas production rate is, the greater the effect of dynamic capillary pressure on the cumulative gas production, formation pressure, and flowing bottomhole pressure will be. By taking the dynamic capillary pressure into account, it can be more accurate to predict the performance of a gas reservoir and the length of stable production period, allowing for making more reasonable development schemes and thus improving the gas recovery in a tight sandstone reservoir.

Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations

2005 ◽  
Vol 127 (3) ◽  
pp. 240-247 ◽  
Author(s):  
D. Brant Bennion ◽  
F. Brent Thomas
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
The United States ◽  
Gas Production ◽  
Pressure Effects ◽  
Formation Damage ◽  
Low Permeability ◽  
Gas Reservoirs ◽  
Initial Water ◽  
The Impact

Very low in situ permeability gas reservoirs (Kgas<0.1mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

scholarly journals Effects of Irreducible Fluid Saturation and Gas Entry Pressure on Gas Production from Hydrate-Bearing Clayey Silt Sediments by Depressurization

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-20
Author(s):  
Xiaolong Ma ◽  
Youhong Sun ◽  
Wei Guo ◽  
Rui Jia ◽  
Bing Li
Keyword(s):  
Water Saturation ◽  
Gas Production ◽  
Production Volume ◽  
Water Production ◽  
Shenhu Area ◽  
Gas Saturation ◽  
Fluid Saturation ◽  
Entry Pressure ◽  
Clayey Silt ◽  
Irreducible Water Saturation

Gas hydrates in the Shenhu area are mainly hosted in clayey silt sediments, which have the relatively high irreducible fluid saturation and gas entry pressure. And then, they will have an impact on gas production from hydrate-bearing clayey silt sediments, which was evaluated by the numerical simulations of SH2 site in Shenhu area in this paper. The results showed that, with the increase in irreducible water saturation and irreducible gas saturation, the amount of water production and gas production was obviously reduced. When the irreducible water saturation increased from 0.10 to 0.50, the cumulative CH4 production volume decreased from 1668799 m3 to 1536262 m3, and the cumulative water production volume dropped from 620304 m3 to 564797 m3, respectively. When the irreducible gas saturation increased from 0.01 to 0.05, the cumulative CH4 production volume dropped from 1812522 m3 to 1622121 m3, and the cumulative water production volume dropped from 672088 m3 to 600617 m3, respectively. In addition, the capillary pressure increased obviously with the increase in gas entry pressure, but the effect on gas production was small and the effect on water production could be negligible. In conclusion, irreducible water and gas saturation had an important effect on the gas production from gas hydrate, whereas the effects of gas entry pressure could be ignored.

Mechanism of Overpressure Formation in Deeply Burial Sandstone

2013 ◽  
Vol 295-298 ◽  
pp. 2736-2739
Author(s):  
Hai Yan Hu
Keyword(s):  
Hydrostatic Pressure ◽  
Capillary Pressure ◽  
Driving Force ◽  
Low Permeability ◽  
Gas Generation ◽  
Tight Sandstone ◽  
Gas Accumulation ◽  
Fine Grained ◽  
Sandstone Reservoirs ◽  
Induced Fractures

Overpressure is often encountered in the Jurassic tight and the overpressure is closely associated with gas generation. The pressure transfer from the over-pressurized mudstones to adjacent tight sandstones might occur through overpressure induced-fractures. The fine-grained coal containing Jurassic sandstone is sensitive to compaction, and the porosity decreases dramatically with the increase of overlying load. As gas migrates into the tight sandstones, it must overcome the capillary pressure which is greater than the hydrostatic pressure. The gas charging pressure in the tight sandstone must be higher than the capillary pressure, resulting in an overpressure buildup within the tight sandstones. Gas shows, low permeability and strong diagenesis in the overpressure of the tight sandstone system have been observed. Additionally, capillary seals are identified as playing an important role in the mechanism of the overpressure formation in tight sandstone reservoirs. Overpressure might be a driving force to create induced fractures in the interval, which has applications for crossing-formation migration and gas accumulation.

scholarly journals A Hybrid Model for Simulating Fracturing Fluid Flowback in Tight Sandstone Gas Wells considering a Three-Dimensional Discrete Fracture

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Suran Wang ◽  
Yuhu Bai ◽  
Bingxiang Xu ◽  
Yanzun Li ◽  
Ling Chen ◽  
...  
Keyword(s):  
Production Rate ◽  
Two Phase Flow ◽  
Three Dimensional ◽  
Gas Production ◽  
Production Performance ◽  
Phase Flow ◽  
Fracture Permeability ◽  
Tight Sandstone ◽  
Two Phase ◽  
Discrete Fracture

Abstract Two-phase (gas+water) flow is quite common in tight sandstone gas reservoirs during flowback and early-time production periods. However, many analytical models are restricted to single-phase flow problems and three-dimensional fracture characteristics are seldom considered. Numerical simulations are good choices for this problem, but it is time consuming in gridding and simulating. This paper presents a comprehensive hybrid model to characterize two-phase flow behaviour and predict the production performance of a fractured tight gas well with a three-dimensional discrete fracture. In this approach, the hydraulic fracture is discretized into several panels and the transient flow equation is solved by the finite difference method numerically. A three-dimensional volumetric source function and superposition principle are deployed to capture the flow behaviour in the reservoir analytically. The transient responses are obtained by coupling the flow in the reservoir and three-dimensional discrete fracture dynamically. The accuracy and practicability of the proposed model are validated by the numerical simulation result. The results indicate that the proposed model is highly efficient and precise in simulating the gas/water two-phase flow and evaluating the early-time production performance of fractured tight sandstone gas wells considering a three-dimensional discrete fracture. The results also show that the gas production rate will be overestimated without considering the two-phase flow in the hydraulic fracture. In addition, the influences of fracture permeability, fracture half-length, and matrix permeability on production performance are significant. The gas production rate will be higher with larger fracture permeability at the early production period, but the production curves will merge after fracturing fluid flows back. A larger fracture half-length and matrix permeability can enhance the gas production rate.

scholarly journals Permeability Prediction of Tight Sandstone Reservoirs Using Improved BP Neural Network

2015 ◽  
Vol 8 (1) ◽  
pp. 288-292 ◽  
Author(s):  
Peng Zhu ◽  
Chengyan Lin ◽  
Peng Wu ◽  
Ruifeng Fan ◽  
Hualian Zhang ◽  
...  
Keyword(s):  
Neural Network ◽  
Network Model ◽  
Neural Network Model ◽  
Bp Neural Network ◽  
Water Saturation ◽  
Controlling Factors ◽  
Convergence Speed ◽  
Oil Field ◽  
Tight Sandstone ◽  
Irreducible Water Saturation

By analyzing the permeability controlling factors of tight sandstone reservoir in Wuhaozhuang Oil Field, the permeability is considered to be mainly controlled by porosity, clay content, irreducible water saturation and diagenetic coefficient. Because the conventional BP algorithm has its drawbacks such as slow convergence speed and easy falling into the local minimum value, an improved three-layer feed-forward BP neural network model is built by MATLAB neural network toolbox to predict permeability according to the four permeability controlling factors, while studying samples of model are selected based on the representative core analysis data. The simulation based on improved neural network model shows that the improved model has a faster convergence speed and better accuracy. The consistency between model prediction value and lab test value is good and the mean squared error is less. Therefore, the new model can meet the needs of the development geology research of oil field better in the future.

APPLICATION OF RESISTIVITY INVERSION MODELLING TO ENHANCE WATER SATURATION CALCULATIONS FROM WIRELINE LOGS

2000 ◽  
Vol 40 (1) ◽  
pp. 355
Author(s):  
C.J. Shield
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Strong Relationship ◽  
Data Set ◽  
Hydrocarbon Reservoir ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Resistivity Logs ◽  
Resistivity Inversion ◽  
Induction Logs

Water saturation (Sw) values calculated from resistivity or induction logs are often higher than those measured from core-derived capillary pressure (Pc) measurements. The core-derived Sw measurements are commonly applied for reservoir simulation in preference to the log-derived Sw calculations. As it is economically and logistically impractical to core every hydrocarbon reservoir, a method of correlating the core-derived Sw to resistivity/induction logs is required. Two-dimensional resistivity modelling is applied to dual laterolog data to ascertain the applicability of this technique.The Griffin and Scindian/Chinook Fields, offshore Western Australia, have been producing hydrocarbons since 1994 from two early-to-middle Cretaceous reservoirs, the clean quartzose sandstones of the Zeepaard Formation and the overlying glauconitic, quartzose sandstones of the Birdrong Formation. Routine and special core analysis of cores recovered from wells intersecting these two reservoirs creates an excellent data set with which to correlate the good quality wireline log data.A strong relationship is noted between the modelled water saturation from resistivity logs, and the irreducible water saturation measured from core capillary pressure data. Correlation between the core-derived permeability and the invasion diameter calculated from the modelled laterolog data is shown to produce a locally applicable means of estimating permeability from the resistivity modelling results.The evaluation of these data from the Griffin and Scindian/Chinook Fields provides a method for reducing appraisal and development well analysis costs, through the closer integration of core and wireline log data at an earlier stage of the field appraisal phase.

A Comprehensive Approach for Assessing the Impacts of Wettability on Oil Production in Carbonate Reservoirs

2012 ◽  
Author(s):  
Marcos Faerstein ◽  
Paulo Couto ◽  
José Alves
Keyword(s):  
Capillary Pressure ◽  
Case Studies ◽  
Water Saturation ◽  
Oil Production ◽  
Comprehensive Approach ◽  
Carbonate Reservoirs ◽  
Irreducible Water Saturation ◽  
Reservoir Simulator ◽  
Correct Understanding ◽  
The Impact

This paper discusses the impacts that rock wettability may have upon the production and recovery of oil with waterflooding in carbonate reservoirs and how it should be modeled. A broad review of the state of the art has been conducted surveying existing disagreements and knowledge gaps, basic definitions, as well as the correct understanding of the physical phenomena and identification of the characteristics of the various wettability scenarios. Case studies conducted with a black oil reservoir simulator evaluated the impact of different wettability scenarios on oil production and recovery. A comprehensive approach considering all the parameters involved in the wettability modeling was applied to the case studies, showing how the behavior of the reservoir varies as a function of their wettability. This paper shows how relative permeability and capillary pressure should be varied to correctly represent different wettability scenarios and consequently assess its impacts on oil production and recovery. The case studies show that the evaluation of the volume of oil in the reservoir is impacted by wettability through the irreducible water saturation and primary drainage capillary pressure and must be considered in the analyses. In long term analyses, mixed-wet scenarios have a higher oil production and recovery. In medium and short term, the water-wet scenarios have the higher recovery, but in relation to oil production, these scenarios are negatively influenced by the smaller volume of oil in place. The main contribution of this paper is the simultaneous analyses of all the parameters involved in the modeling of wettability showing how they impact the behavior of a reservoir. It shows how the parameters must be varied in a heterogeneous reservoir and how heterogeneity impacts the relevance of wettability in the studies.

Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. D209-D227 ◽  
Author(s):  
Zoya Heidari ◽  
Carlos Torres-Verdín
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Radial Distribution ◽  
Apparent Resistivity ◽  
Water Saturation ◽  
Estimation Method ◽  
Petrophysical Properties ◽  
Fluid Saturation ◽  
Irreducible Water Saturation ◽  
Geophysical Measurements

Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.

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