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Research Papers: Petroleum Engineering

Challenges During Shallow and Deep Carbonate Reservoirs Stimulation

[+] Author and Article Information
Mohamed Mahmoud

Assistant Professor,
King Fahd University of Petroleum and Minerals,
Dhahran 31261, Saudi Arabia
Suez University,
Suez 43721, Egypt
e-mail: mmahmoud@kfupm.edu.sa; mohnasreldin80@gmail.com

Hisham Nasr-El-Din

Professor
Texas A&M University,
College Station, TX 77843
e-mail: Hisham.nasreldin@pe.tamu.edu

Manuscript received November 8, 2013; final manuscript received August 1, 2014; published online August 27, 2014. Guest Editor: Mayank Tyagi.

J. Energy Resour. Technol 137(1), 012902 (Aug 27, 2014) (8 pages) Paper No: JERT-13-1314; doi: 10.1115/1.4028230 History: Received November 08, 2013; Revised August 01, 2014

Carbonate reservoir stimulation has been carried out for years using HCl or HCl-based fluids. High HCl concentration should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide which is very soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems to the well tubular. Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents, such as HEDTA (hydroxyl ethylene diamine triacetic acid) and GLDA (glutamic –N, N-diacetic acid), have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction, low leak-off rate, and low corrosion rates. In this study, the different equations and parameters that can be used in matrix acid treatment were summarized to scale up the laboratory conditions to the field conditions. The conditions where HCl or chelating agents can be used were optimized and in this paper. The leak-off rate was determined using the data from coreflood experiments and computed tomography (CT) scans. Indiana limestone cores of average permeability of 1 md and core lengths of 6 and 20 in. were used in this study. Chelating agents will be used at pH value of 4 and at concentration of 0.6M, and their performance will be compared with the 15 wt.% HCl. The experimental results showed that HCl has high leak-off rate and caused face dissolution at low injection rate. The model to scale up the linear coreflood results to radial field conditions was developed and can be used to design for the optimum conditions of the matrix acid treatments. Chelating agents can be used to stimulate shallow reservoirs in which HCl may cause face dissolution, because they can penetrate deep with less volume and also they can be used in deep reservoirs where HCl may cause severe corrosion to the well tubular.

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References

Figures

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Fig. 1

Pore volume to breakthrough as a function of injection rate for scenario#1

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Fig. 2

Pore volume to breakthrough as a function of injection rate for scenario#2

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Fig. 3

A schematic diagram of wormhole formation in a linear core (after Wang et al. [18])

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Fig. 4

Leak-off rate as a function of wormhole radius and wormhole length in 1.5 × 6 in. Indiana limestone cores at different injection rates using 15 wt.% HCl at room temperature

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Fig. 5

Core inlet after treating Indiana limestone cores by 15 wt.% HCl at room temperature showing face dissolution due to high leak-off rate

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Fig. 6

Leak-off rate as a function of wormhole radius and wormhole length in 1.5 × 6 in. Indiana limestone cores at different injection rates using 0.6M GLDA at room temperature. Wormholing data for GLDA from Refs. [12], [15], and [19].

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Fig. 7

Performance of GLDA and HCl at low and high temperature. Data for GLDA from Refs. [12], [15], and [19].

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