Reaction Kinetics and Coreflooding Study of High-Temperature Carbonate Reservoir Stimulation Using GLDA in Seawater

Khaled Z Abdelgawad,Abdulazeez Abdulraheem,Salaheldin Elkatatny,Mohamed Mahmoud,Shirish Patil

doi:10.3390/en12183407

Khaled Z Abdelgawad, Abdulazeez Abdulraheem + Show 3 more

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https://doi.org/10.3390/en12183407

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Journal: Energies	Publication Date: Sep 4, 2019
Citations: 19	License type: CC BY 4.0

Affiliation: King Fahd University of Petroleum and Minerals

Abstract

Well stimulation using hydrochloric acid (HCl) is a common practice in carbonate reservoirs to overcome formation damage in the near wellbore area. Using HCl for matrix acidizing has many limitations at high-temperature (HT) conditions, such as tubulars corrosion and face dissolution due to the fast reaction rate. Chelating agents, such as L-glutamic acid-N,N-diacetic acid (GLDA), are alternatives to HCl to overcome these problems. We studied the effect of diluting GLDA in seawater on the reaction kinetics with carbonate rocks under HT conditions at low pH (3.8). Results of the reaction of carbonate at 1000 psi and 150, 200, and 250 °F with GLDA prepared in both fresh and seawater, GLDA/DI and GLDA/SW, respectively, are presented. The reaction kinetics experiments were carried out in HT rotating disk apparatus (RDA) at rotational speeds ranging from 500 to 2000 revolutions per minute (RPM) at a fixed temperature. Indiana limestone and Austin chalk were used to studying the effect of rock facies on the reaction of GLDA with rock samples. In both GLDA/DI and GLDA/SW, the reaction regime of 20 wt% GLDA (3.8 pH) with Indiana limestone was mass transfer limited. The reaction rate and diffusion coefficient were highly dependent on the temperature. For Austin chalk, at 200 °F and 1000 psi the diffusion coefficient of GLDA/SW is an order of magnitude of its value with Indiana limestone using the same fluid. Diffusion coefficients were used to estimate the optimum injection rate for stimulating HT carbonate formation and compared with coreflooding results. The data presented in this paper will support the numerical simulation of the acid flow in carbonate reservoirs.

Highlights

Organic and inorganic acids are often injected into carbonate reservoirs to improve oil and gas production
The same temperature effect is obvious at 200 ◦ F (Figure 6c)
Applying Equation (3), diffusion coefficients of 4.59 × 10–6 and−61.07 × 10–5 cm2/s are obtained at Applying Equation (3), diffusion coefficients of 4.59 × 10 and 1.07 × 10−5 cm2 /s are obtained at 200 and 250 °F respectively

Summary

Introduction

Organic and inorganic acids are often injected into carbonate reservoirs to improve oil and gas production. These acids are usually selected based on the type of reservoir rock. In the case of stimulating carbonate formations, acids can dissolve the carbonate rock matrix and create different dissolution features or structures depending on the acid type, injection rate, and formation conditions [1,2,3,4,5,6]. When the retention time of acid in the rock is small, narrow dissolution channels are formed and propagate through the rock and form more branches with continuous acid injection [8,9]. An optimum channel formed during acid injection at the minimum volume of acid injected and yield the highest permeability increase is known as a wormhole [4,10,11]

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