Use of Zeta Potential To Maximize Sand Free Rate: A New Approach on Sand Control

Author(s):  
Alfredo Mendez ◽  
Dan E. Johnson ◽  
Sarkis Kakadjian
2016 ◽  
Vol 31 (01) ◽  
pp. 004-015 ◽  
Author(s):  
Mehmet Parlar ◽  
Raymond J. Tibbles ◽  
Bala Gadiyar ◽  
Bryan Stamm

2014 ◽  
Author(s):  
David Leslie Mason ◽  
Hesham Shamma ◽  
Ron van Petegem ◽  
Mahmoud Naguib ◽  
Hisham Mousa ◽  
...  

2021 ◽  
Author(s):  
Jagaan Selladurai ◽  
Cheol Hwan Roh ◽  
Amr Zeidan ◽  
Saurabh Anand ◽  
Bahrom Madon ◽  
...  

Abstract Malaysian clastic reservoirs are plagued with high fines content which rapidly deteriorates the productivity from wells completed with conventional form of sand control techniques. To mitigate the fines production issue, Petronas recently successfully completed 3 reservoirs in two wells in Field-D using enhanced gravel pack technique. This paper explains in detail the workflow, challenges such as depleted reservoirs, coal streaks, and nearby water contacts and operational execution for the successful re-defined extension pack jobs. This new approach consists of a re-defined Extension Pack / Frac Pack job with fine movement control resin and a re-defined perforation strategy. Perforation strategy consists of limited number of 180 deg phasing non-oriented perforations done under dynamic underbalance conditions. The key requirement to have fracturing as a sand control method is to have a tip screen out (TSO) or high net pressure placement to ensure the fracture has good conductivity. To obtain a good TSO, data acquisition is of paramount importance. The fracturing jobs in the Field – D wells were preceded with step-rate tests, injection tests, minifrac and Diagnostic Fracture Injection Test (DFIT). The data from diagnostic tests were used diligently to have best possible fracturing treatment in the target zones. Excellent pack factors of greater than 500 lbs. per ft were obtained for all the treatment jobs using only linear gel with proppant concentration up to 7 ppa. This high pack factor translates to very good frac conductivity which is essential in fracturing for sand control. Some of the fracturing treatments concluded with a TSO signature which is a big achievement considering the challenges that were associated with fracturing in Field – D. In addition, DFIT and ACA (After Closure Analysis) was performed to estimate permeability and results were compared with various techniques such as log derived and formation tester permeability. Ultimate objective from this analysis is to have a work-flow which can screen candidate wells for such treatments from openhole logs and give an estimated liquid rate post treatment. Also, the workflow for planning and executing fracturing jobs will be presented for Malaysian clastic reservoirs. This work-flow will be vetted against the extensive diagnostic and fracturing data that has been acquired during fracturing treatments in Field – D. Design, actual diagnostic, and fracturing data will be presented in this paper. It is expected that this modified form of sand and fines control will help in reducing the fines issue in Field – D to a great extent along with expected incremental in oil production. If long term production sustainability is proven, similar approach will be adopted by Petronas and can be shared amongst other South East Asia operators in many similar other fields.


2020 ◽  
Author(s):  
Walter Nunez ◽  
Brian Valencia ◽  
Rosana Polo ◽  
William Vera ◽  
Silvia Lizcano ◽  
...  
Keyword(s):  

2020 ◽  
Author(s):  
Miftah Hidayat ◽  
Jan Vinogradov ◽  
Stefan Iglauer ◽  
Mohammad Sarmadivaleh

<p>Electrochemical interactions of calcite with brines in natural subsurface settings have received ample attention in the last decades due to the broad range of their applications. These interactions can be described by an electrical property termed the zeta potential. Many numerical simulation studies using surface complexation modelling (SCM) have been performed to investigate the relationship between the zeta potential and a wide range of salinities and complex brine compositions. Although most of the simulated results, especially in low salinity conditions, successfully match the experimentally measured zeta potential, the simulated zeta potential for high salinity conditions is still poorly understood.</p><p>In this study, we present a new approach of SCM to simulate the zeta potential by considering the actual molecular-scale phenomena at the calcite-brine interface. Unlike previous SCM studies, our model considers the hydrated diameter of ions as the distance of approach, which depends on salinity. We also consider the permittivity of the Stern layer as a function of salinity, which is consistent with previous unrelated studies. We calculate the capacitance for each salinity based on the relationship between the hydrated diameter of ions and the permittivity of the Stern layer. Moreover, all calcite-brine surface reactions are described by new equilibrium constants independent of salinity and composition of brines.</p><p>Our results show that the simulated zeta potential which is obtained from our SCM at a broad range of salinities is successfully matched with the published experimental data for two different carbonate rock samples as long as the salinity dependence of the hydration diameter and electrical permittivity is accounted for. We find that the potential determining ions (Ca<sup>2+</sup>, Mg<sup>2+</sup>, SO<sub>4</sub><sup>2-</sup>, HCO<sub>3</sub><sup>-</sup>,CO<sub>3</sub><sup>2-</sup>) play a dominating role compared to the indifferent ions (Na<sup>+</sup>, Cl<sup>-</sup>) in the calcite-brine surface reactions. The Implications of our findings are significant for wettability evaluation, characterisation of shallow and deep aquifers and CO<sub>2</sub> geological sequestration.</p>


2017 ◽  
Vol 2017 ◽  
pp. 1-10 ◽  
Author(s):  
Son Tung Pham

This paper aims to develop a numerical model that can be used in sand control during production phase of an oil and gas well. The model is able to predict not only the onset of sand production using critical bottom hole pressure inferred from geomechanical modelling, but also the mass of sand produced versus time as well as the change of porosity versus space and time using hydromechanical modelling. A detailed workflow of the modelling was presented with each step of calculations. The empirical parameters were calibrated using laboratory data. Then the modelling was applied in a case study of an oilfield in Cuu Long basin. In addition, a sensitivity study of the effect of drawdown pressure was presented in this paper. Moreover, a comparison between results of different hydromechanical models was also addressed. The outcome of this paper demonstrated the possibility of modelling the sand production mass in real cases, opening a new approach in sand control in petroleum industry.


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