A Study of Water Coning Control in Oil Wells by Injected or Natural FLow Barriers Using Scaled Physical Model and Numerical Simulator

2002 ◽  
Author(s):  
Sarmad S. Siddiqi ◽  
Andrew K. Wojtanowicz
Keyword(s):  
Physical Model ◽  
Oil Wells ◽  
Water Coning ◽  
Natural Flow ◽  
Numerical Simulator

Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq

2021 ◽  
Author(s):  
Xueqing Tang ◽  
Ruifeng Wang ◽  
Zhongliang Cheng ◽  
Hui Lu
Keyword(s):  
High Pressure ◽  
Heavy Oil ◽  
Oil Quality ◽  
Oil Wells ◽  
Gas Condensate ◽  
Oil Viscosity ◽  
Foamy Oil ◽  
Artificial Lift ◽  
Water Coning ◽  
The Dead

Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.

METHODS TO FIND COORDINATES OF OIL WELLS – CONTAMINATORS OF THE ENVIRONMENT

2019 ◽  
pp. 72-80
Author(s):  
Ya. M. Semchuk ◽  
H. D. Lialiuk-Viter ◽  
G. M. Kryvenko
Keyword(s):  
Chemical Properties ◽  
Field Research ◽  
Oil Wells ◽  
Subsurface Water ◽  
Main Method ◽  
Chemical Indicators ◽  
Natural Flow ◽  
Physical And Chemical ◽  
Selection Of ◽  
And Chemical Properties

We have analyzed methods that are used to locate oil wells which pollute subsurface water. The main method to find coordinates is to run indicators in a well. It has been found out that a substance which would be absent in natural water should be selected among the range of chemical indicators. The selection of certain dyes is determined by physical and chemical properties of aquifers in order to eliminate sorption and dispersion processes. Two types of field research are recommended. The first scheme involves putting of the indicator into the well under conditions of natural flow, and the second scheme is the injection of substance into the well. The article points out the drawbacks of this method. It has also examined hydro chemical method to determine the coordinates which is based on the chemical analysis of samples taken from wells. We have also analyzed the method which uses hydrodynamic research to determine sources of contamination of aquifers. That is to disturb static equilibrium in the aquifer by intensive sample taking from the well which is the contamination source.

scholarly journals Estimation of Water Breakthrough Using Numerical Simulation

2019 ◽  
Vol 26 (3) ◽  
pp. 73-81
Author(s):  
Almanar Faleh ◽  
Jalal A. Al-Sudani
Keyword(s):  
Numerical Simulation ◽  
Vertical Direction ◽  
Simulation Models ◽  
Breakthrough Time ◽  
Time Model ◽  
Specific Strength ◽  
Wide Range ◽  
Water Coning ◽  
Fluid Properties ◽  
Numerical Simulator

Water coning is one of the most important phenomena that affect the oil production from oil reservoirs having bottom water aquifers. Empirical model has been developed based on numerical simulator results verified for wide range variation of density difference, viscosity ratio, perforated well interval, vertical to horizontal permeability ratio and well to reservoir radius ratio; the effect of all these parameters on breakthrough time of raising water have been recorded for five different oil flow rate. Since, the model reflects the real situations of reservoir-aquifer zone systems; in which the aquifer has a specific strength to support the reservoir pressure drop depending on its characteristics and water properties. Moreover, the numerical model has been constructed using very fine grids near the wellbore especially in vertical direction, so that very accurate results can be obtained. and (625)runs were performed to generate the breakthrough time model using the numerical simulator verifying all parameters affecting on breakthrough time. The results show that water coning is complex phenomena that depends on all reservoir and fluid properties; the dynamic critical flow rates affected simultaneously by both of the displacing fluid zones. The results show that the breakthrough time of the presented formula provides extreme accuracy with many numerical simulator cases of same reservoir and fluid properties; thus, the suggested formula can be considered as an alternative, quick and easy use tool than numerical simulation models, which consumes time and efforts.

Segregated production method for oil wells with active water coning

1994 ◽  
Vol 11 (1) ◽  
pp. 21-35 ◽  
Author(s):  
Andrew K. Wojtanowicz ◽  
Hui Xu ◽  
Zaki Bassiouni
Keyword(s):  
Production Method ◽  
Oil Wells ◽  
Water Coning

scholarly journals A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Yuhan Wang ◽  
Zhengdong Lei ◽  
Zhenhua Xu ◽  
Jie Liu ◽  
Xiaokun Zhang ◽  
...  
Keyword(s):  
Physical Model ◽  
Hydraulic Fracture ◽  
Material Balance ◽  
Oil Wells ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Fracture System ◽  
Fracture Parameters ◽  
Shale Oil Reservoirs ◽  
Water Ratio

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field.

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