scholarly journals Waterflood optimization using an injector producer pair recovery factor, a novel approach

2021 ◽  
Vol 11 (2) ◽  
pp. 949-959 ◽  
Author(s):  
Nasser Alizadeh ◽  
Ben Salek
Keyword(s):  
Produced Water ◽  
High Water ◽  
Weighting Factor ◽  
Injection Rate ◽  
Recovery Factor ◽  
Rock Properties ◽  
Sweep Efficiency ◽  
Full Field ◽  
Novel Approach ◽  
Water Cut

AbstractThis paper presents an approach to optimize the recovery factor and sweep efficiency in a waterflooding process by automating the optimum injection rate calculations for water injectors using streamline simulation. A streamline simulator is an appropriate tool for modern waterflood management and can be used to determine the dynamic interaction between injector and producer pairs, which will vary over time based on sweep efficiency and operational changes. A streamline simulator can be used to identify injectors, which are not supporting production and contributing mainly to water producing wells. Streamlines illustrate natural fluid-flow paths in the reservoir, which are based on fluid properties, rock properties, well distribution and well rates across the reservoir. A bundle of connected streamlines can provide the oil in place between an injector/producer pair at any given time during a simulation run. Thus, the well pair recovery factors for each injector/producer pair, the produced water cut and the weighting factor for each injector are determined. Multiplying this weighting factor by the injection rates determines the new injection rate for each injector. For a well pair water cut that is lower than the average field water cut, the injection rate will be increased and vice versa. Given a finite volume of injection water, there will be a re-allocating of water from a well pair with a low recovery factor and high water cut and redistributing the water to injectors supporting low water cut producers, thus maximizing the recovery factor and reducing the field water production. The described approach is an automated procedure during the reservoir simulation run, making it appropriate for full field waterflood optimization with many injectors and producers in high-resolution heterogeneous brown reservoirs. This approach can reduce the water cut and increase the recovery factor and extend the life of the waterflooded oil fields. It was initially tested with a synthetic model and later with an actual reservoir model, which will be described in this paper.

scholarly journals Gas-assisted gravity drainage process for improved oil recovery in Bao Den fractured basement reservoir

2016 ◽  
Vol 19 (1) ◽  
pp. 161-168
Author(s):  
Tuan Van Nguyen ◽  
Xuan Van Tran
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
High Water ◽  
Injection Rate ◽  
Oil Field ◽  
Gravity Drainage ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
North West ◽  
Water Cut

Gas injection has been widely used for Improved Oil Recovery (IOR)/ Enhanced Oil Recovery (EOR) processes in oil reservoirs. Unlike the conventional gas injection (CGI) modes of CGI and Water Alternating Gas (WAG), the Gas-Assisted Gravity Drainage (GAGD) process takes advantage of the natural segregation of reservoir fluids to provide gravity stable oil displacement. It has been proved that GAGD Process results in better sweep efficiency and higher microscopic displacement to recover the bypassed oil from un-swept regions in the reservoir. Therefore, dry gas has been considered for injection in fractured basement reservoir, Bao Den (BD) oil field located in Cuu Long basin through the GAGD process application. This field, with a 5-year production history, has nine production wells and is surrounded by a strong active edge aquifer from the North-West and the South East flanks. The depth of basement granite top is about 2,800 mTVDss with a vertical oil column of 1,500m. The pilot GAGD project has been designed to test an isolated domain in the BD fractured basement reservoir where there is favorable reservoir conditions to implement GAGD. Both reservoir simulation and Lab test have been run and confirmed the feasibility and the benefit of GAGD project in the selected area.The Dry gas will be periodically injected through existing wellwith high water cut production that located in the isolated area. As the injected gas rises to the top to form a gas zone pushing GOC (gas oil contact) downward, and may push WOC (water oil contact) to lower part of this producer (or even away from bottom of the well bore) could lower down water cut when switch this well back to production mode. The matched reservoir model with reservoir and fluid properties have been used to implement sensitivity analysis, the result indicated that there is significantly oil incremental and water cut reduction by GAGDapplication. Many different scenarios have run to find the optimal reservoir performance through GAGD process. Among these runs, the optimal scenario, which has distinct target, requires high levels of gas injection rate to attain the maximum cumulative oil production.

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.

scholarly journals Auto-optimization of production-injection rate for reservoirs with strong natural aquifer at ultra-high water cut stage

2019 ◽  
Vol 46 (4) ◽  
pp. 804-809 ◽  
Author(s):  
Zhanxiang LEI ◽  
Longxin MU ◽  
Hui ZHAO ◽  
Jian LIU ◽  
Heping CHEN ◽  
...  
Keyword(s):  
High Water ◽  
Injection Rate ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
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.

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.

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.

Maximize the Recovery Factor of Offshore High Water Cut Reservoir

2019 ◽  
Author(s):  
Kuiqian Ma ◽  
Zhaobo Sun ◽  
Hongfu Shi
Keyword(s):  
High Water ◽  
Recovery Factor ◽  
High Water Cut ◽  
Water Cut

scholarly journals Effect of Emulsification on Enhanced Oil Recovery during Surfactant/Polymer Flooding in the Homogeneous and Heterogeneous Porous Media

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiaoyan Wang ◽  
Jie Zhang ◽  
Guangyu Yuan ◽  
Wei Wang ◽  
Yanbin Liang ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
High Water ◽  
Heterogeneous Porous Media ◽  
Recovery Factor ◽  
Water Flooding ◽  
Core Flooding ◽  
Positive Role ◽  
High Water Cut ◽  
Water Cut

Surfactant polymer (SP) flooding has become an important enhanced oil recovery (EOR) technique for the high-water cut mature oilfield. Emulsification in the SP flooding process is regarded as a powerful mark for the successful application of SP flooding in the filed scale. People believe emulsification plays a positive role in EOR. This paper uses one-dimensional homogenous core flooding experiments and parallel core flooding experiments to examine the effect of emulsification on the oil recoveries in the SP flooding process. 0.3 pore volume (PV) of emulsions which are prepared using ultralow interface intension (IFT) SP solution and crude oil with stirring method was injected into core models to mimic the emulsification process in SP flooding, followed by 0.35 PV of SP flooding to flood emulsions and remaining oil. The other experiment was preformed 0.65 PV of SP flooding as a contrast. We found SP flooding can obviously enhance oil recovery factor by 25% after water flooding in both homogeneous and heterogeneous cores. Compared to SP flooding, emulsification can contribute an additional recovery factor of 3.8% in parallel core flooding experiments. But there is no difference on recoveries in homogenous core flooding experiments. It indicates that the role of emulsification during SP flooding will be more significant for oil recoveries in a heterogeneous reservoir rather than a homogeneous reservoir.

The success story of Windalia waterflood optimisation through integrated asset management in a mature field

2011 ◽  
Vol 51 (2) ◽  
pp. 726
Author(s):  
Lina Hartanto ◽  
Wisnu Widjanarko ◽  
Diala Muna
Keyword(s):  
Oil Recovery ◽  
Asset Management ◽  
Produced Water ◽  
Lessons Learned ◽  
Full Potential ◽  
Success Story ◽  
Sweep Efficiency ◽  
Full Field ◽  
Injection Flow ◽  
Mature Field

Australia’s Barrow Island Windalia reservoir—the nation’s largest onshore waterflood—was developed in the late 1960s. The Barrow Island oilfield is Chevron Australia’s only mature waterflood, comprising more than 220 active injectors. The injectors pressurise and increase oil recovery from the geologically complex, low-permeable and heterogeneous Windalia Sand Member. To date it is estimated that the value of waterflooding has effectively reduced the field decline rate from approximately 18 % per annum to less than 2 %—adding millions of barrels in recovery and years on to productive field life. In September of 2008, the Windalia Waterflood achieved full field restitution. This involved the replacement and commissioning of glass-reinforced epoxy injection flow lines, a ring-main network and produced water re-injection facilities. Significant challenges were overcome in the process of realising the restitution’s full potential. Several waterflood optimisation activities have now been executed to achieve oil uplift and to capitalise on Chevron Australia’s investment. Compounded with restitution, the activities have successfully achieved the asset objective of arresting field production decline. This paper highlights the challenges encountered by the waterflood team, providing insights and lessons learned in the dynamic and holistic nature of waterflood management. It also highlights the interplay of considerations and what is crucial to achieving optimum sweep efficiency and pressurisation.

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