Determination and Implication of Ultimate Water Cut in Well-Spacing Design for Reservoirs with Water Coning

2016 ◽  
Author(s):  
S. Prasun ◽  
A. K Wojtanowicz
Keyword(s):  
Well Spacing ◽  
Water Coning ◽  
Water Cut

Stabilized Water-Cut in Carbonate Naturally-Fractured Reservoirs With Bottom Water With an Implication in Well Spacing Design for Recovery Optimization

2018 ◽  
Author(s):  
Samir Prasun ◽  
A. K. Wojtanowicz
Keyword(s):  
Final Stage ◽  
Bottom Water ◽  
Fractured Reservoirs ◽  
Capillary Forces ◽  
Naturally Fractured Reservoirs ◽  
Oil Displacement ◽  
Well Spacing ◽  
Constant Rate ◽  
Water Coning ◽  
Water Cut

Maximum stabilized water-cut (WC), also known as ultimate water-cut in a reservoir with bottom-water coning, provides important information to decide if reservoir development is economical. To date, theory and determination of stabilized water-cut consider only single-permeability systems so there is a need to extend this concept to Naturally Fractured Reservoirs (NFRs) in carbonate rocks — known for severe bottom water invasion. This work provides insight of the water coning mechanism in NFR and proposes an analytical method for computing stabilized water-cut and relating to well-spacing design. Simulated experiments on a variety of bottom-water hydrophobic NFRs have been designed, conducted, and analyzed using dual-porosity/dual-permeability (DPDP) commercial software. They show a pattern of water cut development in NFR comprising the early water breakthrough and very rapid increase followed by water cut-stabilization stage, and the final stage with progressive water-cut. The initial steply increase of water-cut corresponds to water invading the fractures. The stabilized WC production stage occurs when oil is displaced at a constant rate from matrix to the water-producing fractures. During this stage water invades matrix at small values of capillary forces so they do not oppose water invasion. In contrast, during the final stage (with progressing water cut) the capillary forces grow significantly so they effectively oppose water invasion resulting in progressive water cut. A simple analytical model explains the constant rate of oil displacement by considering the driving effect of gravity and viscous forces at a very small value of capillary pressure. The constant oil displacement effect is confirmed with a designed series of simulation experiments for a variety of bottom-water NFRs. Statistical analysis of the results correlates the duration of the stabilized WC stage with production rate and well-spacing and provides the basis for optimizing the recovery. Results show that stabilized water-cut stage does not significantly contribute to recovery, so the stage needs to be avoided. Proposed is a new method for finding the optimum well spacing that eliminates the stabilized WC stage while maximizing recovery. The method is demonstrated for the base-case NFR.

Stabilized Water-Cut in Carbonate Naturally Fractured Reservoirs With Bottom Water With an Implication in Well Spacing Design for Recovery Optimization

2020 ◽  
Vol 142 (3) ◽  
Author(s):  
Samir Prasun ◽  
Andrew K. Wojtanowicz
Keyword(s):  
Final Stage ◽  
Bottom Water ◽  
Fractured Reservoirs ◽  
Capillary Forces ◽  
Naturally Fractured Reservoirs ◽  
Oil Displacement ◽  
Well Spacing ◽  
Constant Rate ◽  
Water Coning ◽  
Water Cut

Abstract Maximum stabilized water-cut (WC), also known as ultimate water-cut in a reservoir with bottom-water coning, provides important information to decide if reservoir development is economical. To date, theory and determination of stabilized water-cut consider only single-permeability systems so there is a need to extend this concept to naturally fractured reservoirs (NFRs) in carbonate rocks—known for severe bottom-water invasion. This work provides insight of the water coning mechanism in NFR and proposes an analytical method for computing stabilized water-cut and relating to well-spacing design. Simulated experiments on a variety of bottom-water hydrophobic NFRs have been designed, conducted, and analyzed using the dual-porosity/dual-permeability (DPDP) commercial software. They show a pattern of water-cut development in NFR comprising the early water breakthrough and very rapid increase followed by water-cut stabilization stage, and the final stage with progressive water-cut. The initial steply increase of water-cut corresponds to water invading the fractures. The stabilized WC production stage occurs when oil is displaced at a constant rate from matrix to the water-producing fractures. During this stage, water invades matrix at small values of capillary forces so they do not oppose water invasion. In contrast, during the final stage (with progressing water cut), the capillary forces grow significantly so they effectively oppose water invasion resulting in progressive water cut. A simple analytical model explains the constant rate of oil displacement by considering the driving effect of gravity and viscous forces at a very small value of capillary pressure. The constant oil displacement effect is confirmed with a designed series of simulation experiments for a variety of bottom-water NFRs. Statistical analysis of the results correlates the duration of the stabilized WC stage with production rate and well-spacing and provides the basis for optimizing the recovery. Results show that stabilized water-cut stage does not significantly contribute to recovery, so the stage needs to be avoided. Proposed is a new method for finding the optimum well spacing that eliminates the stabilized WC stage while maximizing recovery. The method is demonstrated for the base-case NFR.

Determination and Implication of Ultimate Water Cut in Well-Spacing Design for Developed Reservoirs With Water Coning

2018 ◽  
Vol 140 (8) ◽  
Author(s):  
Samir Prasun ◽  
A. K. Wojtanowicz
Keyword(s):  
Production Rate ◽  
Reservoir Properties ◽  
Flow Distortion ◽  
Practical Applications ◽  
Rate Dependent ◽  
Well Spacing ◽  
Water Coning ◽  
Simplifying Assumptions ◽  
Water Cut ◽  
New Formula

Theoretically, ultimate water-cut (WCult) defines stabilized well's oil and water production rates for uncontained oil pay underlain with water. However, in a real multiwell reservoir, the well's drainage area is contained by a no-flow boundary (NFB) that would control water coning, so the WCult concept should be qualified and related to the well-spacing size. Also, the presently used WCult formula derives from several simplifying assumptions, so its validity needs to be verified. The study shows that in multiwell bottom-water reservoirs, the production water-cut would never stabilize (after initial rapid increase) but would continue increasing at slow rate dependent on the production rate and well-spacing size. At each production rate, there is a minimum well-spacing size above which water-cut becomes practically constant at the value defined here as pseudoWCult. A new formula—developed in this study—correlates the minimum well-spacing with reservoir properties. Further, formula for pseudoWCult is derived by considering radial flow distortion effects in the oil and water zones. It is found that for well-spacing larger than the minimum well-spacing, the two effects-when combined-do not change the water-cut value. Thus, in practical applications, for sufficiently large well-spacing, the pseudoWCult values can be computed from the presently used WCult formula. The pseudoWCult concept has potential practical use in well-spacing design for ultimate recovery determined by the water cut economic limit, WCec. When the water-cut economic margin (WCec–WCult) is large, well-spacing has little effect on the ultimate recovery, so large well-spacing could be designed. However, when the water-cut economic margin is small, reservoir development decision should consider increase of final recovery by reducing well-spacing below the minimum well-spacing.

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.

Review of Practical Experience by Polymer Flooding at Daqing

2009 ◽  
Vol 12 (03) ◽  
pp. 470-476 ◽  
Author(s):  
Dongmei Wang ◽  
Huanzhong Dong ◽  
Changsen Lv ◽  
Xiaofei Fu ◽  
Jun Nie
Keyword(s):  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Molecular Weights ◽  
Well Spacing ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut

Summary This paper describes successful practices applied during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. On the basis of laboratory findings, new concepts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir-engineering approaches and technology that is basic for successful application of polymer flooding. These include the following:Proper consideration must be given to the permeability contrast among the oil zones and to interwell continuity, involving the optimum combination of oil strata during flooding and well-pattern design, respectively;Higher polymer molecular weights, a broader range of polymer molecular weights, and higher polymer concentrations are desirable in the injected slugs;The entire polymer-flooding process should be characterized in five stages--with its dynamic behavior distinguished by water-cut changes; -Additional techniques should be considered, such as dynamic monitoring using well logging, well testing, and tracers; effective techniques are also needed for surface mixing, injection facilities, oil production, and produced-water treatment; andContinuous innovation must be a priority during polymer flooding. Introduction China's Daqing oil field entered its ultrahigh-water-cut period after 30 years of exploitation. Just before large-scale polymer-flooding application, the average water-cut was more than 90%. The Daqing oil-field is a large river-delta/lacustrine facies, multilayered with complex geologic conditions and heterogeneous sandstone in an inland basin. After 30 years of waterflooding, many channels and high-permeability streaks were identified in this oil field (Wang and Qian 2002). Laboratory research began in the 1960s, investigating the potential of enhanced-oil-recovery (EOR) processes in the Daqing oil field. After a single-injector polymer flood with a small well spacing of 75 m in 1972, polymer flooding was set on pilot test. During the late 1980s, a pilot project in central Daqing was expanded to a multiwell pattern with larger well spacing. Favorable results from these tests--along with extensive research and engineering from the mid-1980s through the 1990s--confirmed that polymer flooding was the preferred method to improve areal- and vertical-sweep efficiency at Daqing and to provide mobility control (Wang et al. 2002, Wang and Liu 2004). Consequently, the world's largest polymer flood was implemented at Daqing, beginning in 1996. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding boosted the ultimate recovery for the field to more than 50% of original oil in place (OOIP)--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 10 million tons (73 million bbl) per year (sustained for 6 years). The focus of this paper is on polymer flooding, in which sweep efficiency is improved by reducing the water/oil mobility ratio in the reservoir. This paper is not concerned with the use of chemical gel treatments, which attempt to block water flow through fractures and high-permeability strata. Applications of chemical gel treatments in China have been covered elsewhere (Liu et al. 2006).

Inflow Performance and Pressure Interference in Dual-Completed Wells With Water Coning Control

2002 ◽  
Vol 124 (4) ◽  
pp. 253-261 ◽  
Author(s):  
Andrew K. Wojtanowicz ◽  
Ephim I. Shirman
Keyword(s):  
Three Dimensional ◽  
Maximum Pressure ◽  
Water Drainage ◽  
Two Phase ◽  
Drainage Rate ◽  
Water Coning ◽  
Water Cut ◽  
Downhole Water Sink ◽  
Inflow Performance ◽  
Well Completions

Dual-completed wells with Downhole Water Sink (DWS) are used for water coning control in oil reservoirs with bottom water drive. In DWS wells, the second (bottom) completion—placed in the water column—is used for draining water. This prevents the water cone invasion and allows free oil inflow in the top completion. The decision on using DWS or a conventional (single-completed) well is based upon deliverability comparison of the two wells. This paper shows how to describe DWS well deliverability in terms of the top and bottom production rates, water cut, and pressure drawdown. Also, the effect of pressure interference between two well completions on deliverability limits has been studied and qualified experimentally. DWS well deliverability depends on two variables, pressure drawdown and water drainage rate, and is described by a three-dimensional Inflow Performance Domain (IPD). Visual-Basic software based on a new analytical model of IPD has been developed to calculate critical (fluid breakthrough) rates for oil and water. The critical rates identify inflow conditions to the well’s completions—single or two-phase inflow. Also calculated are the values of water cut and maximum pressure drawdown at the well. An example demonstrates the procedure and a complete IPD plot. The experimental study, using a Hele-Shaw physical model of DWS well, demonstrates the reduction of well’s deliverability caused by pressure interference from the second (bottom) completion. The experiments have shown, however, that the deliverability decrease is small and over-compensated by the increase of oil rate due to simultaneous reduction of water cut.

scholarly journals Experimental study on waterflooding development of low-amplitude reservoir with big bottom water

2021 ◽  
Author(s):  
Yanlai Li ◽  
Jie Tan ◽  
Songru Mou ◽  
Chunyan Liu ◽  
Dongdong Yang
Keyword(s):  
Bottom Water ◽  
Water Injection ◽  
Water Reservoir ◽  
High Water ◽  
Recovery Factor ◽  
Low Viscosity ◽  
Well Spacing ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Water Cut

AbstractFor offshore reservoirs with a big bottom water range, the water cut rises quickly and soon enters the ultra-high water cut stage. After entering the ultra-high water cut stage, due to the influence of offshore production facilities, there are few potential tapping measures, so it is urgent to explore the feasibility study of artificial water injection development. The quasi-three-dimensional and two-dimensional displacement experiments are designed using the experimental similarity criteria according to the actual reservoir parameters. Several experimental schemes are designed, fluid physical properties, interlayer distribution, and development mode according to the actual reservoir physical properties. Through the visualization of experimental equipment, the bottom water reservoir is visually stimulated. The displacement and sweep law of natural water drive and artificial water injection in bottom water reservoir with or without an interlayer, different viscosity, and different well spacing is analyzed. The following conclusions are obtained: (1) For reservoirs with a viscosity of 150 cp. The recovery factor after water injection is slightly higher than before water injection. However, the recovery factor is lower than that without injection production. The reason is that the increment of injection conversion is limited to reduce one production well after injection conversion. (2) For reservoirs with a viscosity of 30 cp. The recovery factor after injection is 39.8%, which is slightly higher than 38.9% without injection. (3) For reservoirs with a viscosity of 150 cp. In the case of the interlayer. The recovery factor after injection is 30.7%, which is significantly higher than 24.8% without injection. (4) After the well spacing of the low-viscosity reservoir is reduced, the recovery factor reaches 46.1%, which is higher than 38.9% of the non-infill scheme. After the infill well in a low-viscosity reservoir is transferred to injection, the recovery factor is 45.6%, which has little change compared with non-injection, and most of the cumulative production fluid is water. The feasibility and effect of water flooding in a strong bottom water reservoir are demonstrated. This study provides the basis for the proposal of production well injection conversion and the adjustment of production parameters in the highest water cut stage of a big bottom water reservoir.

EVALUATION AND MANAGEMENT OF THIN OIL COLUMN RESERVOIRS IN AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 64 ◽  
Author(s):  
H. R. Irrgang
Keyword(s):  
Column Height ◽  
Gas Oil ◽  
Well Performance ◽  
Oil Viscosity ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Well Spacing ◽  
Hydrocarbon Reserve ◽  
Water Cut ◽  
Dipping Strata

Thin oil columns represent a common and important class of hydrocarbon reserve which are notoriously difficult to evaluate and produce. This paper provides case studies of examples of these reservoirs in Australia and summarises the production methods, well performance and recovery efficiencies.Thin oil column reservoirs are defined here as reservoirs which will cone both water and gas when produced at commercial rates. The oil zone can have a pancake or rim geometry. Examples within Australia include Bream and Snapper (Gippsland Basin), South Pepper and Chervil (Carnarvon Basin), Chookoo (Eromanga Basin) and Taylor (Surat Basin).Parameters which are particularly important in defining the performance of these reservoirs are: horizontal and vertical permeability, column height, stratigraphie dip, well spacing, and oil viscosity. High horizontal permeability is more critical than in other reservoir types as it controls the effectiveness of gravitational forces in opposing coning and other unwanted flows by reducing pressure gradients. Low vertical permeability mitigates coning but can limit across strike drainage in dipping strata. Oil viscosity is also particularly important, even when the mobility ratio is favourable, as it controls the gas/oil ratio and water cut during coning.As coning (by definition) is inevitable the key production issue is gas cap management. The main options are:Limit gas coning by controlling completion depth and production rates.Allow gas cap shrinkage and 'chase' the oil column upwards via recompletions.Reinject gas to control gas-oil contact position.For the latter two options in particular, ultimate reserves are a strong function of the capacity of the installed production facilities, especially offshore, where fixed operating costs are high. When gas cap management is not compromised, reserves increase with higher total fluid withdrawal rates. Examples of the various gas cap management and production strategies are included.Both horizontal (South Pepper, Bream) and conventional (Chookoo, Taylor) completion techniques have been applied to thin oil column reservoirs in Australia. Horizontal completions can increase productivity, mitigate coning and increase the well drainage areas (particularly if drilled across dip in heterogeneous reservoirs). However, horizontal completions are particularly vulnerable to poor cement jobs, natural fractures and undesirable fluid contact movements.A variety of other completion techniques have been tried worldwide in thin oil columns with mixed success. These include multiple completions in the water, oil and/or gas to allow separate production, and injection of fluids to make permeability barriers or alter relative permeability.A number of scaling rules are included to assist in using offset field data for evaluation of thin oil column reservoirs. Improved understanding of these complex reservoirs will maximise their economic potential.

Machine learning application to predict the efficiency of water coning prevention

2021 ◽  
pp. 104-113
Author(s):  
E.F. Veliyev ◽  
◽  
A.A. Aliyev ◽  
T.E. Mammadbayli ◽  
◽  
...  
Keyword(s):  
Machine Learning ◽  
Prediction Models ◽  
Support Vector ◽  
Practical Application ◽  
Machine Learning Methods ◽  
Common Causes ◽  
Water Coning ◽  
Resource Intensity ◽  
Water Cut ◽  
Ranking Mechanism

The increase in number of the mature fields is accompanied by an increase in the water cut of the produced fluids. One of the most common causes of this phenomenon is the process of water coning, that is, the breakthrough of the bottom water to the wellbore, in which water flows form a figure similar to a cone. The paper proposes a ranking mechanism based on machine learning methods that allow to significantly reduce the resource intensity of existing prediction models. In order to preserve the simplicity of presentation, the proposed mechanism is considered on the example of one technology - DWL. Obtained results show about 10% smaller deviation values when using the least squares support vector machine in comparison with the ANN. Both developed models demonstrated acceptable results for practical application.

Determination of Optimum Rate in a Condensate Well with a Case of a Wellbore Liquid Loading

2021 ◽  
Author(s):  
Merit P. Ekeregbe
Keyword(s):  
Optimization Method ◽  
Dew Point ◽  
Quadratic Model ◽  
Liquid Loading ◽  
Optimum Rate ◽  
Well Production ◽  
Water Coning ◽  
Point Pressure ◽  
Water Cut ◽  
Bean Size

Abstract Condensate reservoirs are mostly pressure sensitive and keeping the pressure above the dew point pressure in the reservoir is critical to avoid condensate banking in the reservoir. If it occurs, production is highly inhibited and the well may ultimately quit on production under liquid loading. Fluid ratios are important in the management of condensate wells and most critical is the Gas Liquid Ratio (GLR). There is a certain GLR that below it, there will be a liquid loading in the wellbore that could quit the well. Each fluid rate goes with a GLR and the point where there is a reversal of the GLR or CGR trends may present a case of loading scenario and that is taken as the determination reference point. When a condensate well shows an improvement of water cut as the choke bean size is reduced does not necessarily signify a healthy situation and neither a one-point higher water cut with increase in choke bean size mean a water coning situation. When a liquid loading well is beaned up, there is early signs of water coning in the production data but this is just a wellbore production and the BS&W improves as the production rate is further increased. Further investigation is necessary to separate the challenge of water conning from the challenge of too low Gas rate which causes the loading of the liquids in the wellbore. That is the operating envelop to manage condensate well rates: rates too low with a possibility of a liquid loading and rates too high that depicts a case of water conning when water is close to the perforation. This band must be completely exploited to turn the production curve in the positive. This paper provides a strategy to recover a condensate well production with a challenge of liquid loading using a case study. The degree of the severity of the liquid loading can be represented using a power law model with the gradient being the level of severity of the loading. The production improvement is greater than nβ percent where n is the quadratic model number 2 and β is the product of the graphical and Lagrangian-Quadratic alpha parameters. The optimum rate can be determined using the Lagrange Multiplier optimization method to effectively extend the production life of the well.

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