Polymer Systems for Water Shutoff and Profile Modification: A Review Over the Last Decade

Summary Unwanted water production is a serious issue in oil- and gas-producing wells. It causes corrosion, scale, and loss of productivity. One method of treating this problem is to chemically reduce unwanted water. This paper discusses the use of polymer systems for this purpose and presents a thorough review of available literature over the last decade. In this paper, field-application data for various polymer systems are summarized over the range of 40 to 150°C (104 to 302°F). These applications cover a wide range of permeabilities from 20 to 2,720 md in sandstone and carbonate reservoirs around the globe. Moreover, the review revealed that the last decade of developments can be categorized into two major types. The first type is polymer gels for total water shutoff in the near-wellbore region, in which a polymer is crosslinked with either an organic or an inorganic crosslinker. The second type is concerned with deep treatment of water-injection wells diverting fluids away from high-permeability zones (thief zones). These thief zones take most of the injected water, which results in a large amount of unrecovered oil. For the total-blocking gels, various systems were identified, such as polyurethane resins, chromium (Cr3+) crosslinking terpolymers, Cr3+ crosslinking foamed partially hydrolyzed polyacrylamide (PHPA), and nanoparticle polyelectrolyte complexes (PECs) sequestering Cr3+ for elongation of its gelation time with PHPA. In addition, polyethylenimine (PEI) was identified to crosslink various polyacrylamide- (PAM-) based polymers. The Petróleos de Venezuela S.A. (PDVSA) Research and Development Center developed a PAM-based thermally stable polymer and an organic crosslinker. The system is applicable for a wide temperature range from 50 to 160°C (130 to 320°F). For the deep modification of water-injection profiles in water-injection wells, two systems were identified: microspheres prepared from PAM monomers crosslinked with N,N′-methylenebisacrylamide and microspheres produced by crosslinking 2-acrylamido-2-methylpropane sulfonic acid (AMPS) with diacrylamides and methacrylamides of diamines (thermally activated microparticles known as Bright Water). This paper highlights all major developments in these areas.

Download Full-text

Application of the CL-systems technology for water injection wells at an oil and gas field

Istrazivanja i projektovanja za privredu ◽

10.5937/jaes0-31315 ◽

2021 ◽

Vol 19 (3) ◽

pp. 848-853

Author(s):

Liliya Saychenko ◽

Radharkrishnan Karantharath

Keyword(s):

Oil And Gas ◽

Water Injection ◽

Oil And Gas Industry ◽

Field Studies ◽

High Water ◽

Injection Wells ◽

Gas Field ◽

Water Breakthrough ◽

Oil And Gas Field ◽

High Water Cut

To date, the development of the oil and gas industry can be characterized by a decline in the efficiency of the development of hydrocarbon deposits. High water cut-off is often caused by water breaking through a highly permeable reservoir interval, which often leads to the shutdown of wells due to the unprofitability of their further operation. In this paper, the application of straightening the profile log technology for injection wells of the Muravlenkovsky oil and gas field is justified. In the course of this work, the results of field studies are systematized. The reasons for water breakthrough were determined, and the main ways of filtration of the injected water were identified using tracer surveys. The use of CL-systems technology based on polyacrylamide and chromium acetate is recommended. The forecast of the estimated additional oil produced was made.

Download Full-text

Polymer gels for controlling water thief zones in injection wells

CT&F - Ciencia Tecnología y Futuro ◽

10.29047/01225383.215 ◽

2012 ◽

Vol 5 (1) ◽

pp. 37-44 ◽

Cited By ~ 3

Author(s):

Gustavo-Adolfo Maya-Toro ◽

Rubén-Hernán Castro-García ◽

Zarith del Pilar Pachón-Contreras. ◽

Jose-Francisco Zapata-Arango

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Injection Wells ◽

Recovery Processes ◽

Injection Water ◽

Secondary Oil Recovery ◽

High Concentrations ◽

Low Efficiency ◽

Hydrolyzed Polyacrylamide ◽

Positive Results

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.

Download Full-text

Peramalan Kinerja Lapangan SNP Dengan Injeksi Air Menggunakan Metode Material Balance

Journal of Earth Energy Science, Engineering, and Technology ◽

10.25105/jeeset.v1i3.4683 ◽

2018 ◽

Vol 1 (3) ◽

Author(s):

Andre Albert Sahetapy Engel ◽

Rachmat Sudibjo ◽

Muhammad Taufiq Fathaddin

Keyword(s):

Oil And Gas ◽

Water Injection ◽

Material Balance ◽

Oil And Gas Industry ◽

Reservoir Pressure ◽

Injection Wells ◽

Gas Industry ◽

Evaluation Result ◽

Cumulative Production ◽

The Common

<p>The decline in production from of a field is the common problem in the oil and gas industry. One of the causes of the decrease in production is the decline of reservoir pressure. Based on the analisis result, it was found that SNP field had a weak water drive. The most dominant drive of the field was fluid expansion. In order to reduce the problem, a reservoir pressure maintenance effort was required by injecting water. In this research, the effect of water injection to reservoir pressure and cumulative production was analyzed. From the evaluation result, it was found that the existing inejection performance using one injection well to Zones A and B was not optimum. Because, the recovery factor was predicted to 29.11% only.By activating the four injection wells, the recoverty factor could be increase to 31.43%.</p>

Download Full-text

A Nano Method for a Big Challenge: Nanosilica-Based Sealing System for Water Shutoff

10.2118/204840-ms ◽

2021 ◽

Author(s):

Ayman Almohsin ◽

Jin Hung ◽

Mohammed Alabdrabalnabi ◽

Mohammed Sherief

Keyword(s):

Chemical Treatment ◽

Fractured Reservoirs ◽

Gelation Time ◽

Cost Effective ◽

Economic Life ◽

Narrow Particle Size Distribution ◽

Water Production ◽

Water Shutoff ◽

Sandstone Rock ◽

Wide Range

Abstract Minimizing unwanted water production from oil wells is highly required in the petroleum industry. This would lead to improved economic life of mature wells that involve new and innovative technologies. Nanosilica-based sealing fluid has been developed to address problems associated with unwanted water production. The objective of this work is to evaluate a newly developed novel water shutoff system based on nanosilica over a wide range of parameters. This modified nanosilica has a smooth, spherical shape, and are present in a narrow particle size distribution. Therefore, it can be used for water management in different water production mechanisms including high permeability streak, wormhole, and fractured reservoirs. A systematic evaluation of novel nanosilica/activator for water shutoff purposes requires the examination of the chemical properties before, during, and after gelation at given reservoir conditions. These properties are solution initial viscosity, gelation time, injectivity, and strength of the formed gel against applied external forces in different flooding systems. This paper details a promising method to control undesired water production using eco-friendly, cost-effective nanosilica. Experimental results revealed that nanosilica initially exhibited a low viscosity and hence providing a significant advantage in terms of mixing and pumping requirements. Nanosilica gelation time, which is a critical factor in placement of injected-chemical treatment, can be tailored by adjusting the activator concentration to match field requirements at the desired temperature. In addition, core flood tests were conducted in carbonate core plugs, Berea sandstone rock, and artificially fractured (metal tube) to investigate the performance of the chemical treatment. Flow tests clearly indicated that the water production significantly dropped in all tested types of rocks. The environmental scanning electron microscope (SEM) results showed the presence of SiO-rich compounds suggesting that the tested nanosilica product filled the porous media; therefore, it blocked the whole core plug. A novel cost-effective sealant that uses nanotechnology to block the near wellbore region has been developed. The performance and methods controlling its propagation rate into a porous medium will be presented. Based on the outcomes, it must be emphasized that these trivial particles have a promising application in the oil reservoir for water shutoff purposes.

Download Full-text

Lessons Learned From Applications of a New Organic-Oil-Recovery Method That Activates Resident Microbes

SPE Reservoir Evaluation & Engineering ◽

10.2118/145054-pa ◽

2012 ◽

Vol 15 (06) ◽

pp. 688-694 ◽

Cited By ~ 2

Author(s):

R.L.. L. Zahner ◽

S.J.. J. Tapper ◽

B.W.G.. W.G. Marcotte ◽

B.R.. R. Govreau

Keyword(s):

Oil Recovery ◽

Microbial Growth ◽

Water Injection ◽

The United States ◽

Lessons Learned ◽

Injection Wells ◽

Recovery Method ◽

Scientific Analysis ◽

Wide Range

Summary Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells. MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.

Download Full-text

Modeling of Partially Hydrolyzed Polyacrylamide-Hexamine-Hydroquinone Gel System Used for Profile Modification Jobs in the Oil Field

Journal of Petroleum Engineering ◽

10.1155/2013/709248 ◽

2013 ◽

Vol 2013 ◽

pp. 1-11 ◽

Cited By ~ 4

Author(s):

Upendra Singh Yadav ◽

Vikas Mahto

Keyword(s):

Gelation Time ◽

Temperature Stability ◽

Oil Field ◽

Polymer Gel ◽

High Temperature Stability ◽

Injection Wells ◽

Profile Modification ◽

Partially Hydrolyzed Polyacrylamide ◽

Hydrolyzed Polyacrylamide ◽

Gel System

The cross-linked polymer gel systems are being used increasingly to redirect or modify reservoir fluid movement in the vicinity of injection wells for the purpose of permeability/profile modification job in the oil field due to their high temperature stability and capability to provide rigid gel having high mechanical strength. In this study, a partially hydrolyzed polyacrylamide-hexamine-hydroquinonegel is used for the development of polymer gel system. The experimental investigation demonstrates that the gelation time varies with polymer and crosslinker concentration and the temperature. The mathematical model is developed with the help of gelation kinetics of polymer gel and using Arrhenius equation, which relates the gelation time with polymer, crosslinker concentrations, and temperature. The developed model is solved with the help of multivariate regression method. It is observed in this study that the theoretical values of gelation time have good agreement with the experimental values.

Download Full-text

BARROW ISLAND OIL FIELD

The APPEA Journal ◽

10.1071/aj98011 ◽

1999 ◽

Vol 39 (1) ◽

pp. 158 ◽

Cited By ~ 1

Author(s):

G.K. Ellis ◽

A. Pitchford ◽

R.H. Bruce

Keyword(s):

Lower Cretaceous ◽

Middle Jurassic ◽

Upper Cretaceous ◽

Oil And Gas ◽

Water Injection ◽

Water Source ◽

Upper Jurassic ◽

Hydrocarbon Reservoirs ◽

Oil Field ◽

Injection Wells

The Barrow Island Field in the Barrow Sub-basin of the Carnarvon Basin was discovered in 1964 by West Australian Petroleum Pty Limited. It is the largest oil field in Western Australia. Appraisal drilling has defined in-place oil of 200 GL (1,250 MMBBL) and in-place gas of 16.5 Gm3 (580 BCF) primarily in the Lower Cretaceous Windalia Sand Member of the Muderong Shale and in- place gas of 14.5 Gm3 (515 BCF) in Middle Jurassic Biggada Formation. Additional hydrocarbon reservoirs have been discovered, including oil and gas in the Upper Jurassic Dupuy Formation, the Lower Cretaceous Malouet Formation, Flacourt Formation and Tunney Member, Mardie Greensand Member and M zones of the Muderong Shale and in the Upper Cretaceous Gearle Siltstone. Approximately 850 wells have been drilled to appraise and develop these accumulations, and to provide water source and water injection wells to enhance recovery. Production commenced in December 1966, with the first shipment of oil in April 1967. Although numerous hydrocarbon reservoirs have been developed, 95% of the 44 GL (278 MMBBL) of produced oil has been from the Windalia Sand.Structural development of the Barrow Island anticline occurred initially during the Middle Jurassic and continued intermittently during the Cretaceous and Tertiary. Initial charging of the Dupuy and Malouet formations with oil from the Upper Jurassic Dingo Claystone occurred in the Early Cretaceous prior to the development of the shallower closures. Periodic wrench- related movement on the Barrow Fault during the Early to Late Cretaceous produced closures at the Lower Cretaceous reservoirs and provided a catalyst for oil migration and charging of these closures. Significant amounts of an extremely biodegraded component, and several less biodegraded phases are present in the oil in the Windalia Sand, indicating several phases of oil charging of the Barrow structure from Middle and Upper Jurassic sediments. In the Tertiary, gas sourced from Triassic and Jurassic sediments migrated into the Barrow structure via a dilated Barrow Fault, charged the Middle Jurassic Biggada Formation and displaced some of the oil in the Lower Cretaceous reservoirs.

Download Full-text

Gelation Behavior of Polyacrylamide Reinforced with Nano-Silica for Water Shutoff Treatment in Oil Field

Solid State Phenomena ◽

10.4028/www.scientific.net/ssp.307.252 ◽

2020 ◽

Vol 307 ◽

pp. 252-257

Author(s):

Nurhazwane Abdul Fadil ◽

Sonny Irawan ◽

Nur Amelia Mohd Isa ◽

Siti Rohaida Shafian

Keyword(s):

Gelation Time ◽

Silica Content ◽

Oil Field ◽

Nano Silica ◽

Water Shutoff ◽

Silica Concentration ◽

Gelation Behavior ◽

Hydrolyzed Polyacrylamide ◽

Placement Depth ◽

Gel System

Polyacrylamide gel system is widely been used in oilfield for water shutoff treatment. Gelation behavior such as proper gelation time provides a basic guideline on gel placement depth in reservoir layers. In this study, the gelation behavior of partially hydrolyzed polyacrylamide crosslinked with chromium(III) acetate (PHPA/Cr3+) reinforced with nano-silica was studied in term of gelation time and gel stability. The gelation time of PHPA/Cr3+ gel could be controlled with the addition of nano-silica where the gel has shown a delay in gelation time at low concentration of nano-silica. At 0.3 wt.% of nano-silica concentration, the gelation time has shown two times delay compared to the original gel system. The gel at the formulations of 0.7 wt.% and 1.0 wt.% nano-silica content remained stable with H code after 24 hours observation.

Download Full-text