Injection of Polymer for Improved Sweep Efficiency in High Temperature High Salinity Carbonate Reservoirs: Linear X-Ray Aided Flood Front Monitoring

Abstract Over the last few years, ADNOC has systematically investigated a new polymer-based EOR scheme to improve sweep efficiency in high temperature and high salinity (HTHS) carbonate reservoirs in Abu Dhabi (Masalmeh et al., 2014). Consequently, ADNOC has developed a thorough de-risking program for the new EOR concept in these carbonate reservoirs. The de-risking program includes extensive laboratory experimental studies and field injectivity tests to ensure that the selected polymer can be propagated in the target reservoirs. A new polymer with high 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) content was identified, based on extensive laboratory studies (Masalmeh, et al., 2019, Dupuis, et al., 2017, Jouenne 2020), and an initial polymer injectivity test (PIT) was conducted in 2019 at 250°F and salinity >200,000 ppm, with low H2S content (Rachapudi, et al., 2020, Leon and Masalmeh, 2021). The next step for ADNOC was to extend polymer application to harsher field conditions, including higher H2S content. Accordingly, a PIT was designed in preparation for a multi-well pilot This paper presents ADNOC's follow-up PIT, which expands the envelope of polymer flooding to dissolve H2S concentrations of 20 - 40 ppm to confirm injectivity at representative field conditions and in situ polymer performance. The PIT was executed over five months, from February 2021 to July 2021, followed by a chase water flood that will run until December 2021. A total of 108,392 barrels of polymer solution were successfully injected during the PIT. The extensive dataset acquired was used to assess injectivity and in-depth mobility reduction associated with the new polymer. Preliminary results from the PIT suggest that all key performance indicators have been achieved, with a predictable viscosity yield and good injectivity at target rates, consistent with the laboratory data. The use of a down-hole shut-in tool (DHSIT) to acquire pressure fall-off (PFO) data clarified the near-wellbore behaviour of the polymer and allowed optimisation of the PIT programme. This paper assesses the importance of water quality on polymer solution preparation and injection performance and reviews operational data acquired during the testing period. Polymer properties determined during the PIT will be used to optimise field and sector models and will facilitate the evaluation of polymer EOR in other giant, heterogeneous carbonate reservoirs, leading to improved recovery in ADNOC and Middle East reservoirs.

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Ultralow-Interfacial-Tension Foam-Injection Strategy in High-Temperature Ultrahigh-Salinity Fractured Oil-Wet Carbonate Reservoirs

SPE Journal ◽

10.2118/190259-pa ◽

2019 ◽

Vol 24 (06) ◽

pp. 2822-2840 ◽

Cited By ~ 3

Author(s):

Pengfei Dong ◽

Maura C. Puerto ◽

Kun Ma ◽

Khalid Mateen ◽

Guangwei Ren ◽

...

Keyword(s):

High Temperature ◽

Oil Recovery ◽

High Salinity ◽

Salinity Gradient ◽

Carbonate Reservoirs ◽

Sweep Efficiency ◽

Injection Strategy ◽

The Matrix ◽

Ultralow Interfacial Tension ◽

Ultralow Ift

Summary Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil–wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection–strategy investigation of ultralow–interfacial–tension (IFT) foam in a high–temperature (greater than 80°C), ultrahigh–formation–salinity [greater than 23% total dissolved solids (TDS)] fractured oil–wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontal–dilution map was created to simulate frontal–displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk–foam tests were also conducted to study the salinity–gradient effect on the performance of ultralow–IFT foam. Ultralow–IFT foam–injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil–wet core systems with initial oil/brine two–phase saturation. The representative fractured system included a well–defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10−2 to 10−3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow–IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow–IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil–wet systems because of the selective diversion of ultralow–IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high–salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high–salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow–IFT foam process to ensure good foam propagation and high oil–recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow–IFT foam in high–temperature, ultrahigh–salinity fractured oil–wet carbonate reservoirs and investigated the injection strategy to enhance the low–IFT foam performance. The ultralow–IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility–control agent in a fractured system for better sweep efficiency.

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Development of Surfactant-Polymer SP Processes for High Temperature and High Salinity Carbonate Reservoirs

10.2118/191733-ms ◽

2018 ◽

Cited By ~ 2

Author(s):

Pinaki Ghosh ◽

Himanshu Sharma ◽

Kishore K. Mohanty

Keyword(s):

High Temperature ◽

High Salinity ◽

Carbonate Reservoirs

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Wettability Alteration in High Temperature and High Salinity Carbonate Reservoirs

10.2118/147306-ms ◽

2011 ◽

Cited By ~ 8

Author(s):

Gaurav Sharma ◽

Kishore K. Mohanty

Keyword(s):

High Temperature ◽

High Salinity ◽

Carbonate Reservoirs ◽

Wettability Alteration

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Application of Biopolymer to Improve Oil Recovery in High Temperature High Salinity Carbonate Reservoirs

10.2118/177915-ms ◽

2015 ◽

Cited By ~ 8

Author(s):

Syed Mohamid Raza Quadri ◽

Li Jiran ◽

Mohammad Shoaib ◽

Muhammad Rehan Hashmet ◽

Ali M. AlSumaiti ◽

...

Keyword(s):

High Temperature ◽

Oil Recovery ◽

High Salinity ◽

Carbonate Reservoirs

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Mobility of Ethomeen C12 and Carbon Dioxide (CO2) Foam at High Temperature/High Salinity and in Carbonate Cores

SPE Journal ◽

10.2118/179726-pa ◽

2016 ◽

Vol 21 (04) ◽

pp. 1151-1163 ◽

Cited By ~ 44

Author(s):

Leyu Cui ◽

Kun Ma ◽

Maura Puerto ◽

Ahmed A. Abdala ◽

Ivan Tanakov ◽

...

Keyword(s):

Carbon Dioxide ◽

High Temperature ◽

High Salinity ◽

Local Equilibrium ◽

Co2 Flooding ◽

Sweep Efficiency ◽

Co2 Foam ◽

Foam Model ◽

Wide Range ◽

Carbon Dioxide Co2

Summary The low viscosity and density of carbon dioxide (CO2) usually result in the poor sweep efficiency in CO2-flooding processes, especially in heterogeneous formations. Foam is a promising method to control the mobility and thus reduce the CO2 bypass because of the gravity override and heterogeneity of formations. A switchable surfactant, Ethomeen C12, has been reported as an effective CO2-foaming agent in a sandpack with low adsorption on pure-carbonate minerals. Here, the low mobility of Ethomeen C12/CO2 foam at high temperature (120 °C), high pressure (3,400 psi), and high salinity [22 wt% of total dissolved solids (TDS)] was demonstrated in Silurian dolomite cores and in a wide range of foam qualities. The influence of various parameters, including aqueous solubility, thermal and chemical stability, flow rate, foam quality, salinity, temperature, and minimum-pressure gradient (MPG), on CO2 foam was discussed. A local-equilibrium foam model, the dry-out foam model, was used to fit the experimental data for reservoir simulation.

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