Influence Of Production Rate And Oil Viscosity On Water Coning

1974 ◽  
Author(s):  
K. Aziz Thakur ◽  
J. Flores
Keyword(s):  
Production Rate ◽  
Oil Viscosity ◽  
Water Coning

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.

scholarly journals Comparison Between Homogenous and Heterogeneous Reservoirs: A Parametric Study of Water Coning Phenomena

2021 ◽  
Vol 5 (1) ◽  
pp. 119-131
Author(s):  
Frzan F. Ali ◽  
Maha R. Hamoudi ◽  
Akram H. Abdul Wahab
Keyword(s):  
Production Rate ◽  
Oil Production ◽  
Water Production ◽  
Effective Parameters ◽  
Radial Cross Section ◽  
Heterogeneous Reservoirs ◽  
Water Breakthrough ◽  
Water Coning ◽  
Water Cut ◽  
Reservoir Simulator

Water coning is the biggest production problem mechanism in Middle East oil fields, especially in the Kurdistan Region of Iraq. When water production starts to increase, the costs of operations increase. Water production from the coning phenomena results in a reduction in recovery factor from the reservoir. Understanding the key factors impacting this problem can lead to the implementation of efficient methods to prevent and mitigate water coning. The rate of success of any method relies mainly on the ability to identify the mechanism causing the water coning. This is because several reservoir parameters can affect water coning in both homogenous and heterogeneous reservoirs. The objective of this research is to identify the parameters contributing to water coning in both homogenous and heterogeneous reservoirs. A simulation model was created to demonstrate water coning in a single- vertical well in a radial cross-section model in a commercial reservoir simulator. The sensitivity analysis was conducted on a variety of properties separately for both homogenous and heterogeneous reservoirs. The results were categorized by time to water breakthrough, oil production rate and water oil ratio. The results of the simulation work led to a number of conclusions. Firstly, production rate, perforation interval thickness and perforation depth are the most effective parameters on water coning. Secondly, time of water breakthrough is not an adequate indicator on the economic performance of the well, as the water cut is also important. Thirdly, natural fractures have significant contribution on water coning, which leads to less oil production at the end of production time when compared to a conventional reservoir with similar properties.

Polymer Application in High-Water-Cut Wells Enhances Productivity in a Mature Field

2021 ◽  
Vol 73 (09) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Trinidad And Tobago ◽  
Production Rate ◽  
Produced Water ◽  
Oil Production ◽  
High Water ◽  
Water Production ◽  
Oil Viscosity ◽  
High Stakes ◽  
High Water Cut ◽  
Water Cut

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200957, “Application of Specially Designed Polymers in High-Water-Cut Wells: A Holistic Well-Intervention Technology Applied in Umm Gudair Field, Kuwait,” by Ali Abdullah Al-Azmi, SPE, Thanyan Ahmed Al-Yaqout, and Dalal Yousef Al-Jutaili, Kuwait Oil Company, et al., prepared for the 2020 SPE Trinidad and Tobago Section Energy Resources Conference, originally scheduled to be held in Port of Spain, Trinidad and Tobago, 29 June–1 July. The paper has not been peer reviewed. A significant challenge faced in the mature Umm Gudair (UG) field is assurance of hydrocarbon flow through highly water-prone intervals. The complete paper discusses the field implementation of a downhole chemical methodology that has positively affected overall productivity. The treatment was highly modified to address the challenges of electrical-submersible-pump (ESP)-driven well operations, technical difficulties posed by the formation, high-stakes economics, and high water potential from these formations. Field Background and Challenge The UG field is one of the major oil fields in Kuwait (Fig. 1). The Minagish oolite (MO) reservoir is the main oil producer, contributing more than 95% of current production in the UG field. However, water cut has been increasing (approximately 65% at the time of writing). The increasing water cut in the reservoir is posing a major challenge to maintaining the oil-production rate because of the higher mobility of water compared with that of oil. The natural water aquifer support in the reservoir that underlies the oil column extends across the reservoir and is rising continuously. This has led to a decline in the oil-production rate and has prevented oil-producing zones from contributing effectively. The reservoir experiences water-coning phenomena, especially in high-permeability zones. Oil viscosity ranges from 2 to 8 cp, and hydrogen sulfide and carbon dioxide levels are 1.5 and 4%, respectively. During recent years, water production has increased rapidly in wells because of highly conductive, thick, clean carbonate formations with low structural dip as well as some stratified formations. Field production may be constrained by the capacity of the surface facilities; therefore, increased water production has different effects on field operations. The average cost of handling produced water is estimated to be between $5 billion and $10 billion in the US and approximately $40 billion globally. These volumes often are so large that even incremental modifications can have major financial effects. For example, the lift-ing cost of one barrel of oil doubles when water cut reaches 50%, increases fivefold at 80% water cut, and increases twenty-fold at 95% water cut.

A Theoretical and Experimental Coning Study

1975 ◽  
Vol 15 (03) ◽  
pp. 247-254 ◽  
Author(s):  
N. Mungan
Keyword(s):  
Experimental Study ◽  
Numerical Model ◽  
Production Rate ◽  
Oil Recovery ◽  
Symmetry Plane ◽  
Radial Symmetry ◽  
Bottom Plate ◽  
Vertical Permeability ◽  
Water Coning ◽  
Horizontal Permeability

Abstract Experimental and numerical studies were made of water coning in an oil-producing well under two-phase, immiscible, incompressible flow. The model chosen was a pie-shaped, cylindrical sand pack with radial symmetry. Saturations were measured in situ by 70 micro-resistivity probes embedded in the sand pack. Results indicated that the numerical model pack. Results indicated that the numerical model simulated the experiments adequately. Increasing the production rate or the wellbore penetration lead to earlier water breakthrough; however, oil recovery was independent of production rate. As the ratio of gravity to viscous forces increased, the oil recovery at any given WOR became greater; wells should have been spaced closer if the horizontal permeability was low or if the vertical permeability permeability was low or if the vertical permeability was high. High vertical permeability decreased the oil recovery, while the opposite was true for horizontal permeability. In stratified formations, the highest permeability. In stratified formations, the highest oil recovery resulted when the most permeable section was located near the top of the oil-bearing zone. Introduction Coning in oil-producing wells is a problem more common than generally is believed. It occurs in producing formations that are underlain by water, producing formations that are underlain by water, overlain by gas, where a secondary gas cap develops, or are under the conditions of water, gas, or solvent injection. The present oil shortage has resulted in wells being produced at full capacity -- a situation that aggravates coning. Under severe coning conditions, well allowables must be reduced to. a level that minimizes coning and avoids loss of ultimate oil recovery. These considerations make study of the coning phenomenon more important than previously. previously.The two objectives a this study wereto apply a numerical coning model to actual laboratory results to verify validity of the numerical model, andto use the numerical model to study the effect of certain parameters on development of be cone and on the oil-recovery performance. The study was restricted to water coning in oil wells in a reservoir system of cylindrical geometry with radial symmetry. PROCEDURE PROCEDURE SELECTION OF A NUMERICAL MODEL The Blair and Weinaug problem was solved using four different numerical coning models and the solutions obtained were compared with the results of Letkeman and Ridings to select the numerical model to be used in the rest of the study. EXPERIMENTAL STUDY For the experimental study, a pie-shaped, cylindrical coning model was constructed of clear plexiglass. The model was 16 in. high and had a plexiglass. The model was 16 in. high and had a radius of 20 in. and an angle of 30 degrees. It was constructed of 1-in.-thick plexiglass and was supported by a metal frame all around to avoid bulging during flow. To distribute the injected water uniformly across the bottom face of the sand pack, the bottom plate had fluid grooves that were pack, the bottom plate had fluid grooves that were overlain by several layers of 325-mesh monel screen. Seventy micro-resistivity probes were constructed and positioned inside the model for measuring the electrical resistivity. Probes were constructed from two 1/8-in.-square, 100-mesh monel screens positioned parallel to one another and separated by positioned parallel to one another and separated by about 1/4 in. A thin, insulated wire led from each screen through a hole drilled in the side plates of the model to an electrical 70-point junction box, and from there to a specially constructed 70-channel scanner. The scanner could scan any or all of the resistivity probes at a rate ranging from 112 to 60 seconds per probe. A timer permitted continuous scanning or time-lapse scanning ranging from once per hour to once every 8 hours. The output of the per hour to once every 8 hours. The output of the scanner was put through a digital voltmeter to a digital recorder. During a flow experiment, the resistivity at each probe thus could be measured and recorded automatically. The resistivity probes were positioned. on a central symmetry plane, thus permitting measurements far from the boundaries of the model. SPEJ P. 247

Cyclic Steam Stimulation Effect on Skin Factor Reviewed Case Study

2016 ◽  
Vol 818 ◽  
pp. 287-290 ◽  
Author(s):  
Wan Rosli Wan Sulaiman ◽  
Azza Hashim
Keyword(s):  
Production Rate ◽  
Heavy Oil ◽  
Development Program ◽  
Thermal Recovery ◽  
Reservoir Rock ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Cyclic Steam Stimulation ◽  
Heavy Oil Reservoir ◽  
Steam Stimulation

High oil viscosity is a major concern for recovery from heavy oil reservoir. Introducing heat to the formation has proven to be an effective way to improve mobility. The Heat transfer to the oil and reservoir rock is good for thermal recovery. The thermal recovery involves a well-known technique of cyclic steam stimulation which actually effect the nearby well area. Heavy oil reservoir which uses the thermal technique will experience the change of property. Fula North East (FNE) Sudanese field is located in the north-eastern part of Fula sub-basin. According to the development program of FNE, Bentiu layer (of Bentiu group) is the targeted reservoir where the pressure gradient is 285.65 psi/100m, perforation intervals is 540-533 m, and the average oil production rate of single well by applying the cyclic steam stimulation (CSS) is 236 bbl/d. For well- Q, (one of the hot wells) to void the bottom water the average production rate is 191 bbl/d. A minor change is observed in the key properties of the well when the skin affect is varied.

Analytical Modeling of Emulsion Flow at the Edge of a Steam Chamber During a Steam-Assisted-Gravity-Drainage Process

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 353-363 ◽  
Author(s):  
Mahdie Mojarad ◽  
Hassan Dehghanpour
Keyword(s):  
Sensitivity Analysis ◽  
Production Rate ◽  
Flow Rate ◽  
Gravity Drainage ◽  
Oil Viscosity ◽  
Oil Emulsion ◽  
Steam Chamber ◽  
Steam Assisted Gravity Drainage ◽  
Oil Flow ◽  
Water In Oil Emulsion

Summary Recently, different models were proposed to describe two- and three-phase flow at the edge of a steam chamber developed during a steam-assisted-gravity-drainage (SAGD) process. However, 2D-scaled SAGD experiments and recent micromodel visualizations demonstrate that steam condensate is primarily in the form of microbubbles dispersed in the oil phase (water-in-oil emulsion). Therefore, the challenging question is: Can the multiphase Darcy equation be used to describe the transport of water as a discontinuous phase? Furthermore, the physical impact of water as a continuous phase or as microbubbles on oil flow can be different. Water microbubbles increase the apparent oil viscosity, whereas a continuous water phase decreases the oil relative permeability. Investigating the impact of these two phenomena on oil mobility at the steam-chamber edge and on overall oil-production rate during an SAGD process requires development of relevant mathematical models, which is the focus of this paper. In this paper, we develop an analytical model for lateral expansion of the steam chamber that accounts for formation and transport of water-in-oil emulsion. It is assumed that emulsion is generated as a result of condensation of steam, which penetrates into the heated bitumen. The emulsion concentration decreases from a maximum value at the chamber interface to zero far from the interface. The oil viscosity is affected by both temperature gradient caused by heat conduction and microbubble concentration gradient resulting from emulsification. We conduct a sensitivity analysis with the measured data from scaled SAGD experiments. The sensitivity analysis shows that, by increasing the value of m (temperature viscosity parameter), the effect of emulsification on oil-flow rate decreases. It also shows that the effect of temperature on oil mobility is much stronger than that of emulsion. We also compare the model predictions with field production data from several SAGD operations. Butler's model overestimates oil-production rate caused by the single-phase assumption, whereas the proposed model presents more-accurate oil-flow rate, supporting the fact that one should include emulsification effect in the SAGD analysis.

A Depletion Strategy for an Active Bottom-Water Drive Reservoir Using Analytical and Numerical Models—Field Case Study

2009 ◽  
Vol 131 (10) ◽  
Author(s):  
Ibrahim Sami Nashawi ◽  
Ealian H. Al-Anzi ◽  
Yousef S. Hashem
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Bottom Water ◽  
Numerical Models ◽  
Water Production ◽  
Breakthrough Time ◽  
Well Completion ◽  
Water Breakthrough ◽  
Water Coning ◽  
Single Well

Water coning is one of the most serious problems encountered in active bottom-water drive reservoir. It increases the cost of production operations, reduces the efficiency of the depletion mechanism, and decreases the overall oil recovery. Therefore, preventive measures to curtail water coning damaging effects should be well delineated at the early stages of reservoir depletion. Production rate, mobility ratio, well completion design, and reservoir anisotropy are few of the major parameters influencing and promoting water coning. The objective of this paper is to develop a depletion strategy for an active bottom-water drive reservoir that would improve oil recovery, reduce water production due to coning, delay water breakthrough time, and pre-identify wells that are candidates to excessive water production. The proposed depletion strategy does not only take into consideration the reservoir conditions, but also the currently available surface production facilities and future development plan. Analytical methods are first used to obtain preliminary estimates of critical production rate and water breakthrough time, then comprehensive numerical investigation of the relevant parameters affecting water coning behavior is conducted using a single well 3D radial reservoir simulation model.

First Autonomous Inflow Control Device AICD Deployment in Wassana Field

2021 ◽  
Author(s):  
Pongpak Taksaudom ◽  
Tim Kelly ◽  
Atisuda Meeteerawat ◽  
David Carter ◽  
Kannappan Swaminathan ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
High Water ◽  
Oil Field ◽  
Water Production ◽  
Oil Viscosity ◽  
Initial Development ◽  
Water Handling ◽  
Water Breakthrough ◽  
Water Coning

Abstract Wassana oil field is located in the Gulf of Thailand with shallow water depth at approximately 60m. A major challenge is excessive water production which reduces reserves recovery and increases costs associated with produced water handling. The target reservoir is ~20ft thick with active aquifer support. The low oil/ water mobility ratio due to high oil viscosity (≥ 30cp) risks early water coning and high watercuts. All horizontal wells drilled in the Wassana field during the initial development and the first infill campaign were completed as non-ICD openhole standalone screen. For the second infill campaign, the non-ICD simulation showed water breakthrough occurring at the start of production. Once breakthrough occurs, water production rapidly dominates production prompting premature shut-in of production, leaving much unrecovered oil behind. To overcome this problem, Autonomous Inflow Control Devices (AICDs) were introduced to control the production influx profile across the entire horizontal section to delay water coning and to significantly choke back water production when it occurs. With intensive pre-drilled AICD modeling using 3D dynamic time lapse simulation, two wells in the second infill campaign were subsequently chosen to be completed with a configuration of zonal AICDs isolated by swell packers. This design enables isolation across horizontal reservoir section with high water production in tandem with compartmentalization across the contrasting permeability region. Once water breakthrough occurs, the unique autonomous ability of the cyclonic AICD is triggered by exploiting the physics of rotational flow of the vortex-inducing pressure drop principle through a restrictive funnel-type flow-path in a tool with no moving parts. The low viscosity of both water and gas phase promotes higher rotational velocity inducing higher pressure drop or back-pressure of inflow vortex breakdown towards the inlet into the tubing flow, thus helping to further reduce the influx contribution of the high water producing sections. Essentially, the higher watercut zones flowing through the device is restricted more rigorously compared to the oil-prone zones. Both wells were successfully drilled and completed with AICDs in February 2019. Based on actual and early-production history-matched performance, these 2 pilot AICD wells are projecting an improved cumulative oil production gain of up to +7% over 5 years of production. The reduction or delay of water production can benefit the field both in enhancing oil recovery and water handling cost saving.

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