AUTOMATING SANDSTONE ACIDIZING USING A RULE BASED SYSTEM Ali A. Garrouch Haitham M. Lababidi

1. AUTOMATING SANDSTONE ACIDIZING USING A RULE BASED SYSTEM Ali A. Garrouch Haitham M. Lababidi AbAllah Ebrahim Kuwait University

2. REFERENCE • Ebrahim, A., Garrouch, A.A., and Lababidi, H. 2014, Automating sandstone acidizing using a rule-based system, Journal of Petroleum Exploration and Production Technology, v. 4, no. 4, p. 381-396. 2

3. Outline • Purpose of Acidizing Oil an Gas Fields • Sandstone Acidizing Stages • Causes of Failure of Sandstone Acidizing • Challenge/Study Objectives • Expert System Development • Expert System Validation • Conclusions • Reference 3

4. Damage Types - Considered Particle damage from drilling Fines migration Clay swelling Polymer residue from drilling Bacterial infestation Surfactant stabilized emulsions Water blocks

5. Zone of altered permeability ks, near a well. r s p e r w h k s Zone of altered permeability r e e

6. Near well-bore zone: ideal, real and stimulated bottom- hole pressures. r w r s k Reservoir Pressure k s Stimulated well p (due to stimulation) s p Undamaged (Ideal) well w p (due to damage) s Damaged (Real) well

7. pR Natural flow-rate Pwf qo p How Does a Well Produce? pwh pflowline Nodal Analysis pwf

8. Types of Damage , , , Begin by estimating the damage skin (Sd) from the total skin: Evaluate single skin ( Spp, Sp , S , SG, Sf)

9. 0 20 40 60 80 100 4250 Oil 4300 4350 3,750 STB/D 4400 0.1 4450 0.01 0.001 4500 1 10 100 1000 0.0001 0.001 0.01 0.1 1 10 GR, API Openhole and Production log Traces MG Well Depth ft Dp/Dq psi/STB/D Rt, ohm-m Dt, hr

10. Sandstone Acidizing Stages • Pre-flush • Main Acid: 12% HCl-3% HF • Over-flush 10

11. Pre-flush Stage • Usually HCl (5-15% in strength) • Displaces water, minimizing contact of HF acid with Na+ and K+ ions. • HCl removes CaCO3 cementing material 11

12. Main Acid Stage • Usually 12% HCl-3% HF • HF reacts with clays, fines, drilling mudcake, and silica to improve near-wellbore permeability. • HCl keeps pH low and helps to prevent secondary HF reactions. 12

13. Traditional Guidelines 13

14. Overflush • Displacement of acid flush away from wellbore area • Oil wells: NH4Cl/Weak HCl/mutual solvent (if necessary) • Surfactant/Mutual Solvent: • Leave formation water-wet • Facilitate flow-back • Nitrogen: Promotes flow-back in low pressure wells • Results are not always as expected. 14

15. Causes of Failure of Sandstone Acidizing The global success rate for sandstone acidizing is generally about 30%. A quote by a Leonard Kalfayan “With acidizing, there are many more exceptions to the rules than there are rules. In fact, true success in acidizing is associated with the better understanding of the exceptions.” 15

16. Causes of Failure of Sandstone Acidizing • poor candidate selection. • lack of mineralogical information • wrong acid design, • use of inappropriate acid additives, • insufficient iron control. • Formation of emulsions • Formation of asphaltene sludge 16

17. Effect of HCl:HF Acid Strength on Sludging

18. Effect of HCl Strength on Sludging

19. Causes of Failure of Sandstone Acidizing The major defects of HF are the formation of by-products like: • calcium fluoride (CaF2), with calcareous material • sodium hexafluorosilicate (Na2SiF6) • hydrated silica (SiO2.2H2O) • potassium hexafluorosilicate (K2SiF6) 19

20. Causes of Failure of Sandstone Acidizing The major defects of HCl is the formation of precipitates • Ferrous Hydroxide (Fe(OH2), if HCl is neutralized and pH~7 • Gelatinous precipitates in contact with Zeolites (natrolite, analcime) • Ferric Hydroxide (Fe(OH3), • Iron sulfide scale (FeS), if do not use a reducing and a sequestering agent.

21. Challenge/Study Objectives • Design a sandstone acidizing job that is damage type specific, taking into account acid-mineralogy interaction and acid-crude interaction. • Multiple damage types may be suspected, and all should be considered in designing the treatment. • This is a very perplexing task to the practicing engineer.

22. Expert System Development The acidizing advice must account for the following variables: • Damage Type • Rock Mineralogy • Reservoir Temperature • Rock Permeability • Formation fluids • Amount, type, distribution of clays • Degree of rock consolidation • Presence of sour gas

23. Expert System Development Methodology The treatment design will include the following stages: • Formation oil displacement stage • Formation water displacement stage • Acetic acid stage • HCl pre-flush stage • Main acid stage • Over-flush stage

24. Expert System Development Acid Types Expanded • Fluoboric acid: a clay acid • Phosphonic acid blends • Acidic chelant-based blends • Mud acids • EDTA (Ethylene diamene tetracetic acid) • HCL/Acetic acid/Citric acid/Formic acid • Erythorbic acid

25. Fluoboric Acid • Fluoboric acid is recommended when the sandstone contains potassic minerals to avoid damaging precipitates and in the case of fines migration owing to its fines stabilization properties.

26. Acid – chelant blends Acidic-Chelant based blends: are obtained by mixing a chelating agent with an acid based salt. Boric acid, or ammonium bifloride are examples of acid based salts. Examples of a chelating agent: EDTA, HACA

27. Acid-chelant blends • The advantage of chelant based fluids is their ability to • Dissolve both calcium and aluminosilicates • Prevent the possible precipitation of reaction by-products by sequestering many of the metal ions present in the aqueous solution: ca2+, Fe2+, Al3+ ions. • Treat formations with low clay content. • Treat formations with high calcite content • Treat formations with high iron content. • Treat formations with Zeolite bearing minerals. • Treatment restricted for high temperature formations

28. Phosphonic acid blends • The phosphonic acid formulation offers the following benefits: • Retarded reaction rate, hence the ability to get the acid deeper into the formation before becoming completely spent. • No risk of insoluble precipitates such as CaF2, Na2SiF6, K2SiF6 and SiO2.2H2O. • The ability to leave the formation water-wet.

29. Expert System Structure 29

30. Expert System Development – Decision Trees 30

31. Stage no. 2: Formation Water Displacement Stage Inject water with ammonium chloride (NH4CL) at concentrations between 3% and 8% depending on the formation water salinity

32. Stage no. 3: Acetic Acid Pre-flush Stage Are there any iron compounds in the formation: - pyrite, or - siderite, or - hematite, or - Magnetite, or - Antcerite ? Yes No Are there any - chlorite clay, or - mixed layer clay, or - Illite Inject 3% to 10% acetic acid according to Table below: Yes Are there any zeolites like - analcime, or - natrolite ? No Yes No No action needed

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34. Expert System Development – Decision Trees 34

35. Expert System Development – Decision Trees 35

36. Expert System Development – Decision Trees 36

37. Expert System Development – Decision Trees 37

38. Expert System Development – Decision Trees 38

39. Expert System Log in Details http://lababidi.chemeng.kuniv.edu/WBES/ Username: KCUser88 Password: KC@q88 39

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