Expanding Polymer Injectivity Tests on a Second Giant Carbonate UAE Oil Reservoir at High Salinity & High Temperature Conditions.

2021 ◽  
Author(s):  
S.A. Baloch ◽  
J.M. Leon ◽  
S.K. Masalmeh ◽  
D. Chappell ◽  
J. Brodie ◽  
...  
Keyword(s):  
High Temperature ◽  
Polymer Solution ◽  
High Salinity ◽  
Laboratory Data ◽  
Experimental Studies ◽  
Carbonate Reservoirs ◽  
Field Conditions ◽  
Sweep Efficiency ◽  
Tertiary Butyl ◽  
Solution Preparation

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.

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

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2822-2840 ◽  
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.

Analysis of the World's First Polymer Injectivity Test in a Carbonate Reservoir Under Extreme Harsh Conditions in ADNOC's Reservoirs

2021 ◽  
Author(s):  
Juan Manuel Leon ◽  
Shehadeh K. Masalmeh ◽  
Siqing Xu ◽  
Ali M. AlSumaiti ◽  
Ahmed A. BinAmro ◽  
...  
Keyword(s):  
High Temperature ◽  
Laboratory Experiments ◽  
High Salinity ◽  
Laboratory Data ◽  
Injection Pressure ◽  
Carbonate Reservoir ◽  
Experimental Program ◽  
Full Field ◽  
Harsh Conditions

Abstract Assessing polymer injectivity for EOR field applications is highly important and challenging. An excessive injectivity reduction during and after polymer injection may potentially affect the well integrity and recovery efficiency and consequently, injection strategy and the economics of the polymer projects. Moreover, well conditions such as skin, completion configuration, and injection water quality can significantly impact polymer injectivity. Additionally, the presence of fractures or micro-fractures may govern injection pressure. In contrast, historic field applications have shown that polymer injectivity is in general better than expected from simulations or laboratory data. In the laboratory experiments, the polymer injectivity has been evaluated by injection of significant amounts of pore volumes of polymer at relevant well-injection rates. In addition, several experiments were performed to measure the complex in-situ rheology expected to dominate the flow near the wellbore This paper presents the analysis of the the world's first polymer injectivity test (PIT) conducted in a high temperature and high salinity (HTHS) carbonate reservoir in Abu Dhabi as part of a comprehensive de-risking program for a new polymer-based EOR scheme proposed by ADNOC for these challenging carbonate reservoirs (see Masalmeh et. al., 2014). The de-risking program includes an extensive laboratory experimental program and field injectivity test to ensure that the identified polymer can be injected and propagated in the target formation before multi-well pilot and full-field implementation stages. Experimental laboratory data and the field injectivity test results are presented in earlier publications (Masalmeh et. al., 2019; Rachapudi et. al., 2020) and references therein. This PIT is the world's first polymer injectivity test in a carbonate reservoir under such harsh conditions of high salinity, high content of divalent ions and high temperature. In addition, the polymer used during the test has never been field-tested before. Therefore, the results of the PIT interpretation will help to de-risk the suitable polymer for the future inter-well pilot for the new proposed EOR Polymer-based scheme and it is a game-changer to unlock several opportunities for different Chemical EOR applications on full-field scale in other reservoirs with similar characteristics. A single well radial simulation model was built to integrate the surveillance data during PIT and the extensive laboratory experiments. Morever, multiple Pressure Fall Off Tests (PFOs) during the same periods were analyzed and intergaretd in the model.The study assessed the effect of polymer viscosity on mobility reduction, evaluated the polymer bank propagation, investigated the effect of the skin build-up, residual resistance factor (RRF) and shear effects on the well injectivity. Additionally, a comprehensive assisted history match method and robust simulation sensitivity analysis was implemented, thousands of sensitivity simulation runs were performed to capture several possible injection scenarios and validate laboratory parameters. The simulation study confirmed that the PIT could be interpreted using the laboratory-measured polymer parameters such as polymer bulk viscosity, in-situ rheology, RRF and adsorption.

Polymer in-Situ Rheology in Carbonate Reservoirs

2021 ◽  
Author(s):  
Tormod Skauge ◽  
Kenneth Sorbie ◽  
Ali Al-Sumaiti ◽  
Shehadeh Masalmeh ◽  
Arne Skauge
Keyword(s):  
Polymer Solution ◽  
Carbonate Rock ◽  
High Salinity ◽  
Polymer Flooding ◽  
Resistance Factor ◽  
Carbonate Reservoirs ◽  
Permeability Reduction ◽  
Polymer Flood ◽  
Core Flood

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.

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

2015 ◽  
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

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

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1151-1163 ◽  
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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