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 The paper has not been peer reviewed.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.

New Gel Aggregates To Improve Sweep Efficiency During Waterflooding

2011 ◽  
Vol 14 (01) ◽  
pp. 120-128 ◽  
Author(s):  
Guanglun Lei ◽  
Lingling Li ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Low Cost ◽  
Oil Production ◽  
High Water ◽  
Resistance Factor ◽  
Water Production ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Productivity Decline ◽  
High Water Cut ◽  
Water Cut

Summary A common problem for oil production is excessive water production, which can lead to rapid productivity decline and significant increases in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injectors, the injection profiles are uneven and, as a result, large amounts of oil are left behind the water front. Many chemical systems have been used to control water production and improve recovery from reservoirs with high water cut. Inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or crosslinked gels, especially polyacrylamide-based systems, are mainly used because of their relatively low cost and their supposed selectivity. In this paper, microspheres (5–30 μm) were synthesized using acrylamide monomers crosslinked with an organic crosslinker. They can be suspended in water and can be pumped in sandstone formations. They can plug some of the pore throats and, thus, force injected water to change its direction and increase the sweep efficiency. A high-pressure/high-temperature (HP/HT) rheometer was used to measure G (elastic modulus) and G" (viscous modulus) of these aggregates. Experimental results indicate that these microspheres are stable in solutions with 20,000 ppm NaCl at 175°F. They can expand up to five times their original size in deionized water and show good elasticity. The results of sandpack tests show that the microspheres can flow through cores with permeability greater than 500 md and can increase the resistance factor by eight to 25 times and the residual resistance factor by nine times. The addition of microspheres to polymer solutions increased the resistance factor beyond that obtained with the polymer solution alone. Field data using microspheres showed significant improvements in the injection profile and enhancements in oil production.

Fracture Treatment Design in the Lower Miocene Reservoir, Offshore Viet Nam

2021 ◽  
Author(s):  
Truong Nguyen Huu
Keyword(s):  
Production Rate ◽  
Oil Production ◽  
High Water ◽  
Oil Field ◽  
Base Case ◽  
Fracture Conductivity ◽  
Lower Miocene ◽  
High Water Cut ◽  
Water Cut ◽  
Fractured Well

Abstract In the past decades, most oil explotation in the White Tiger oil field was produced from the basement reservoir. However, in recent years, these pay zones consist of basement reservoirs, Oligocene reservoirs, and Miocene reservoirs of which oil field s have been declined in oil production rate due to several issues such as complex fracture network, high heterogeneity formation, high water cut, and the reduction of reservoir pressure. The huge issues in the most production wells at basement reservoir were high water cut and it has been significantly increasing during oil production yearly. Therefore, the total amount of oil production in all pay zones sharply decreased with time. At present, the lower Miocene reservoir is one of the best tight oil reservoirs to produce oil extractrion. The lower Miocene reservoir has been faced some issues such as high heterogeneity, complex structure, catastrophic clay swelling, low connectivity among the fractures, low effective wellbore radius and the reservoir that is hig h temperature up to 120°C, the closure pressure up to 6680psi, reservoir pressure up to 4500 psi, reservoir depth up to 3000m. Another reason low conductivity consists of both low reservoir porosity ranging from 1% of the hard shale to 10% of the sandstone formation, and the low permeability raining from 1md to 10md. By considering the various recovery methods, the integrated hydraulic fracturing stimulation is the best tool to successfully stimulate this reservoir, which method allows an increase in oil production rate. In the post fractured well has been shown an increase in productivity over 3 folds in comparison with the base case with fracture half-length nearly 75m, and fracture conductivity about 5400md.ft, which production rate is higher than the production rate of the base case. In addition, the proppant mass is used of 133,067 lbs of which the first main stage is to pump sinter lite bauxite proppant type of 20/40 into the fractures and the next big stage is to pump sintered ball bauxite proppant size of 16/30 into the fractures, which not only isolate proppant flow back but also increase fracture conductivity at the near wellbore as wel as high productivity rate after fractured well. To improve proppant transport, fract uring fluid systems consist of Guar polymer concentration of 11.2 pptg with these additives to form a total leak-off coefficient of 0.00227 ft/min0.5.

Application of Specially Designed Polymers in High Water Cut Wells- A Holistic Well-Intervention Technology Applied in Umm Gudair Field, Kuwait

2021 ◽  
Author(s):  
Ali Abdullah Al-Azmi ◽  
Thanyan Ahmed Al-Yaqout ◽  
Dalal Yousef Al-Jutaili ◽  
Kutbuddin Bhatia ◽  
Amr Abdelbaky ◽  
...  
Keyword(s):  
Best Practice ◽  
Produced Water ◽  
Positive Impact ◽  
High Water ◽  
Direct Result ◽  
Water Production ◽  
Well Test ◽  
Field Development ◽  
High Water Cut ◽  
Water Cut

Abstract Excessive water production from hydrocarbon reservoirs is a serious issue faced by the industry, particularly for mature fields. Higher water cut adversely affects the economics of the producing wells, thus it is undesirable. Disposal and reinjection of ever-increasing volumes of produced water poses additional liability. A significant challenge faced in the mature Umm Gudair field is assuring hydrocarbon flow through high water-prone intervals. In recent times, field development strategies have begun to prioritize new well intervention technology because of the advantages of minimized water cut, higher production rates, and improved overall reserve recovery (hydrocarbon in place). This paper discusses the field implementation of a downhole chemical methodology, "first of its kind" designed and applied, that has created a positive impact in overall productivity. To solve these challenges, the treatment was highly modified as fit-for-purpose to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stakes economics, and high-water potential from these formations. A unique Organically Crosslinked Polymer (OCP) system with a tail-in Rigid Setting Material (RSM) system was implemented as a porosity-fill sealant in a high-water-cut well to selectively reduce water production. A pre-flush was pumped ahead of the treatment to remove deposits that could have prevented the polymer from effective gelation. The treatment was then overdisplaced with brine. The OCP system is injected into the formation as a low viscosity solution using the spot and hesitation squeeze method via bullheading. It activates at a predicted time to form a 3-D rigid hydrogel to completely shut off matrix permeability, fractures, fissures, and channels, thus creating an artificial barrier seal in the reservoir. The tail-in near wellbore RSM system rapidly develops a high compressive strength to avoid any formation loss before setting. This holistic approach helps to create a robust sealant for blocking the unwanted water-producing zone, impeding water flow, and facilitating increased hydrocarbon flow. A direct comparison of the application of this system with conventional cement squeeze treatments is presented to illustrate the advantage of having a deep matrix penetration for a more efficient water shutoff in this field. A direct result of the implemented treatment is that the post-operation well test and production data showed a high-sustained production at lower rate with significantly reduced watercut, confirming this technology is one of successful chemical water shut off techniques this field. This paper summarizes the candidate selection, design processes, challenges encountered, and production response, and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.

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.

scholarly journals New Waterflooding Characteristic Curves Based on Cumulative Water Injection

2020 ◽  
Vol 2020 ◽  
pp. 1-12
Author(s):  
Zhiwang Yuan ◽  
Zhiping Li ◽  
Li Yang ◽  
Yingchun Zhang
Keyword(s):  
Characteristic Curve ◽  
Water Injection ◽  
Material Balance ◽  
Oil Production ◽  
High Water ◽  
Difficult Problem ◽  
Prediction Errors ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Water Cut

When a conventional waterflooding characteristic curve (WFCC) is used to predict cumulative oil production at a certain stage, the curve depends on the predicted water cut at the predicted cutoff point, but forecasting the water cut is very difficult. For the reservoirs whose pressure is maintained by water injection, based on the water-oil phase seepage theory and the principle of material balance, the equations relating the cumulative oil production and cumulative water injection at the moderately high water cut stage and the ultrahigh water cut stage are derived and termed the Yuan-A and Yuan-B curves, respectively. And then, we theoretically analyze the causes of the prediction errors of cumulative oil production by the Yuan-A curve and give suggestions. In addition, at the ultrahigh water cut stage, the Yuan-B water cut prediction formula is established, which can predict the water cut according to the cumulative water injection and solve the difficult problem of water cut prediction. The application results show Yuan-A and Yuan-B curves are applied to forecast oil production based on cumulative water injection data obtained by the balance of injection and production, avoiding reliance on the water cut forecast and solving the problems of predicting the cumulative oil production of producers or reservoirs that have not yet shown the decline rule. Furthermore, the formulas are simple and convenient, providing certain guiding significance for the prediction of cumulative oil production and water cut for the same reservoir types.

Fieldwide Application of Autonomous Inflow Control Valve in Increasing the Field Recovery in One of the Matured Fields in the Sultanate of Oman: Case Study

2021 ◽  
Author(s):  
Salim Buwauqi ◽  
Ali Al Jumah ◽  
Abdulhameed Shabini ◽  
Ameera Harrasi ◽  
Tejas Kalyani ◽  
...  
Keyword(s):  
Control Valve ◽  
Oil Production ◽  
Horizontal Wells ◽  
High Water ◽  
Lessons Learned ◽  
Water Production ◽  
Sultanate Of Oman ◽  
Well Performance ◽  
Reservoir Conditions ◽  
Water Cut

Abstract One of the largest operators in the Sultanate of Oman discovered a clastic reservoir field in 1980 and put it on production in 1985. The field produces viscous oil, ranging from 200 - 2000+ cP at reservoir conditions. Over 75% of the wells drilled are horizontal wells and the field is one of the largest producers in the Sultanate of Oman. The field challenges include strong aquifer, high permeability zones/faults and large fluid mobility contrast have resulted that most of the wells started with very high-water cuts. The current field water cut is over 94%. This paper details operator's meticulous journey in qualification, field trials followed by field-wide implementation and performance evaluation of Autonomous Inflow Control Valve (AICV) technology in reducing water production and increasing oil production significantly. AICV can precisely identify the fluid flowing through it and shutting-off the high water or gas saturated zones autonomously while stimulating oil production from healthy oil-saturated zones. Like other AICDs (Autonomous Inflow Control Device) AICV can differentiate the fluid flowing through it via fluid properties such as viscosity and density at reservoir conditions. However, AICVs performance is superior due to its advanced design based on Hagen-Poiseuille and Bernoulli's principles. This paper describes an AICV completion design workflow involving a multi-disciplinary team as well as some of the field evaluation criteria to evaluate AICV well performance in the existing and in the new wells. The operator has completed several dozens of production wells with AICV technology in the field since 2018-19. Based on the field performance review, it has shown the benefit of accelerating oil production as well as reduction of unwanted water which not only reduces the OPEX of these wells but at the same time enormous positive impact on the environment. Many AICV wells started with just 25-40 % water cut and are still producing with low water cut and higher oil production. Based on the initial field-wide assessment, it is also envisaged that AICV wells will assist in achieving higher field recovery. Also, AICV helped in mitigating the facility constraints of handling produced water which will allow the operator continued to drill in-fill horizontal wells. Finally, the paper also discusses in detail the long-term performance results of some of the wells and their impact on cumulative field recovery as well as lessons learned to further optimise the well performance. The technology has a profound impact on improved sweep efficiency and as well plays an instrumental role in reducing the carbon footprint by reducing the significant water production at the surface. It is concluded that AICV technology has extended the field and wells life and proved to be the most cost-effective field-proven technology for the water shut-off application.

Application of Fine Water Plugging Technology With Coiled Tubing in High Water Cut Wells

2018 ◽  
Author(s):  
Jie Wang ◽  
Fujian Zhou ◽  
Lufeng Zhang ◽  
Fan Fan ◽  
Hong Yang
Keyword(s):  
Produced Water ◽  
Water Layer ◽  
High Water ◽  
Gas Production ◽  
Cement Slurry ◽  
Coiled Tubing ◽  
Slurry System ◽  
High Water Cut ◽  
Water Cut ◽  
Water Gas

Water logging problem in late production reservoir with abundant edge-bottom water and water-gas layer stagger is one of the main factors that lead to production wells stop flow. For the water plugging problem during gas well production, the common operation is coiled tubing through casing. So, coiled tubing technology without moving production string is explored. X oilfield is located in Sichuan basin of China southwest and belongs to the origin of gas pipeline from Sichuan to China east. Its main gas producing area is carbonatite full of edge water and controlled by structural and lithology. The relationship between water and gas is complex and water-gas system is independent of different blocks and different layers. Because the main gas producing layer is close to the water layer, lots of gas producing wells stop spray for high water cut. At the meantime, the difficulty and risk of water plugging increases for its high depth of main gas producing layer and high temperature at the well bottom. To solve the problem above, cement slurry system with the characteristics of high temperature and sulfur resistant and channeling preventing is developed. At the same time, the cement slurry system has low friction and high liquidity and is easy to flow through the coiled tubing. Besides, cement slurry pollution is reduced and the success rate of gas well produced water plugging is improved by the combination of coiled tubing and cementing process and the construction technology optimization, software simulation and laboratory evaluation is carried out. The key step is that log analysis of water and gas distribution is done first. Then, tubing-expansion bridge plug is placed under the water layer and the cement slurry is sent to the desired location. At last, coiled tubing is put down after cement solidification and gas production is recovered. The measurement of coiled tubing and cement slurry system is positive for water plugging in gas wells with high depth and temperature. The oilfield test results show that daily gas production is improved largely and liquid production is reduced by 90% of 4 wells with high water cut through water plugging. Besides, operation cost is reduced and the pollution problem caused by produced water is also solved, which can provide certain significance for the same type wells need water plugging operation.

Sign in / Sign up

Export Citation Format

Share Document