Laboratory Study of Injection Strategy for Low-Tension-Gas Flooding in High Salinity, Tight Carbonate Reservoirs

2018 ◽  
Author(s):  
A. Das ◽  
N. Nguyen ◽  
R. Farajzadeh ◽  
J. G. Southwick ◽  
S. Vicent-Bonnieu ◽  
...  
Keyword(s):  
Laboratory Study ◽  
High Salinity ◽  
Carbonate Reservoirs ◽  
Injection Strategy ◽  
Tight Carbonate ◽  
Gas Flooding ◽  
Low Tension

Low-Tension Gas (LTG) Injection Strategy in High Salinity and High Temperature Sandstone Reservoirs

2015 ◽  
Author(s):  
N. Nguyen ◽  
Guangwei Ren ◽  
K. Mateen ◽  
P. R. Cordelier ◽  
D. C. Morel ◽  
...  
Keyword(s):  
High Temperature ◽  
High Salinity ◽  
Injection Strategy ◽  
Sandstone Reservoirs ◽  
Low Tension

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.

Laboratory Study of CO2 Foam Flooding in High Temperature, High Salinity Carbonate Reservoirs Using Co-injection Technique

2018 ◽  
Vol 32 (2) ◽  
pp. 1416-1422 ◽  
Author(s):  
Ali M. AlSumaiti ◽  
Muhammad R. Hashmet ◽  
Waleed S. AlAmeri ◽  
Evans Anto-Darkwah
Keyword(s):  
High Temperature ◽  
Laboratory Study ◽  
High Salinity ◽  
Carbonate Reservoirs ◽  
Injection Technique ◽  
Co2 Foam ◽  
Foam Flooding

Laboratory Study of Alkyl Ether Sulfonates for Improved Oil Recovery in High-Salinity Carbonate Reservoirs: A Case Study

2010 ◽  
Vol 24 (6) ◽  
pp. 3655-3660 ◽  
Author(s):  
Mohamed Aoudia ◽  
Rashid S. Al-Maamari ◽  
Moein Nabipour ◽  
Ali S. Al-Bemani ◽  
Shahab Ayatollahi
Keyword(s):  
Laboratory Study ◽  
Oil Recovery ◽  
High Salinity ◽  
Carbonate Reservoirs ◽  
Alkyl Ether ◽  
Improved Oil Recovery

Using Logging and Seismic Data to Identify Boundaries Between Different OWC Units in a Deepwater Carbonate Reservoirs

2021 ◽  
Author(s):  
Kangxu Ren ◽  
Junfeng Zhao ◽  
Jian Zhao ◽  
Xilong Sun
Keyword(s):  
Seismic Data ◽  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Sedimentary Process ◽  
Core Samples ◽  
Tight Carbonate ◽  
Porosity And Permeability ◽  
Seismic Sections ◽  
Parameters Inversion

Abstract At least three very different oil-water contacts (OWC) encountered in the deepwater, huge anticline, pre-salt carbonate reservoirs of X oilfield, Santos Basin, Brazil. The boundaries identification between different OWC units was very important to help calculating the reserves in place, which was the core factor for the development campaign. Based on analysis of wells pressure interference testing data, and interpretation of tight intervals in boreholes, predicating the pre-salt distribution of igneous rocks, intrusion baked aureoles, the silicification and the high GR carbonate rocks, the viewpoint of boundaries developed between different OWC sub-units in the lower parts of this complex carbonate reservoirs had been better understood. Core samples, logging curves, including conventional logging and other special types such as NMR, UBI and ECS, as well as the multi-parameters inversion seismic data, were adopted to confirm the tight intervals in boreholes and to predicate the possible divided boundaries between wells. In the X oilfield, hundreds of meters pre-salt carbonate reservoir had been confirmed to be laterally connected, i.e., the connected intervals including almost the whole Barra Velha Formation and/or the main parts of the Itapema Formation. However, in the middle and/or the lower sections of pre-salt target layers, the situation changed because there developed many complicated tight bodies, which were formed by intrusive diabase dykes and/or sills and the tight carbonate rocks. Many pre-salt inner-layers diabases in X oilfield had very low porosity and permeability. The tight carbonate rocks mostly developed either during early sedimentary process or by latter intrusion metamorphism and/or silicification. Tight bodies were firstly identified in drilled wells with the help of core samples and logging curves. Then, the continuous boundary were discerned on inversion seismic sections marked by wells. This paper showed the idea of coupling the different OWC units in a deepwater pre-salt carbonate play with complicated tight bodies. With the marking of wells, spatial distributions of tight layers were successfully discerned and predicated on inversion seismic sections.

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.

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