Day 1 summary ! Inflow vs Outflow ! Well stimulation: Fraccing and Matrix stimulation ! Matrix stimulation ! Sandstones: Only Damage Skin removed, S dam = 0 ! ! Chemistry complex Carbonates: Damage bypassed, Sdam = ‐2 ! Chemistry relatively simple ! Sources of damage What is the general purpose of s5mula5on?! ! Making sure that the connection between reservoir and well is not the bottleneck for production Which are the two main goals of well s5mula5on? ! Removal of near well bore damage ! Increase of natural productivity How are the two goals achieved? Name three major sources of damage ! Chemical methods (Acid) ! Mechanical methods (Fracturing) ! Mud related damage ! Lost completion fluids ! clay problems; clay swelling, clay & fines migration What is the most appropriate treatment for None, no stimulation candidate 2 mD gas well with a skin of 1.5 and in which losses occurred during comple5on? An oil well with a high skin in a sandstone forma5on containing streaks of up to 25% calcite has been damage by mud losses. What is the best type of acid to be used? Which are the four main phases in s5mula5on design? Oct-19-15 HCl or organic, No HF! • Candidate selection and damage analysis • Fluids and additives recommendation • Pumping schedule and flow (diversion) simulation • Post‐job analysis Classroom exercise Name the 5 main items to investigate whether a well is a matrix stimulation candidate Well performance – WIQI Mechanical problems Skin analysis PLT Damage assessment A well is producing from a sandstone reservoir of 20 mD with 40% oil saturation. Under which conditions is this well in general a stimulation candidate? When it is producing less than 50% water, not close to abandonment and the tubing and production facilities can handle extra production A well has a total skin of 21 of 2 fold which two thirds can be attributed to formation damage. What is the order of magnitude of production improvement an acid treatment could deliver? Oct-19-15 Classroom exercise What are the essential differences between carbonate and sandstone acidising? No HF Damage by‐pass rather than removal Which factors control wormhole formation Surface Reaction Rate Diffusion Rate Injection Rate Oct-19-15 What needs to be checked before a ! Cement quality stimulation treatment can be ! Pressure limitations executed on a well? ! Pumprates and fracturing ! Perforations ! Corrosion concerns ! Erosion concerns Which are the perforation ! perforation diameter ‐ large conditions favor a successful matrix ! shot density ‐ high stimulation treatment? ! perforation phasing ‐ 120o or better ! perforation length – large What are the corrosion protection ! Less than 0.05 lb/ft2 weight loss of requirements for an acid treatment? tubular steel ! No pitting ! In case of sour wells (H2S), no stress corrosion cracking ! Always use corrosion inhibitors ! Use intensifiers if needed to meet above criteria How long should the well be shut‐ in after an acid treatment? Oct-19-15 Best practice: return spent acid to surface immediately after the treatment Name the most important mineral components of a sandstone with respect to acid treatments Can HF/HCl mixtures be used in: ! High carbonate content ! Presence of wax ! Damage caused by clay particles Describe the three spending stages in sandstone acidising Oct-19-15 Quartz Feldspars Clays ! Kaolinite ! Montmorillonite or smectite ! Illite ! Chlorite Carbonates Not if it is more than 10% No, wax will not be removed by acid Yes in most cases, but not in very high temperatures or extremely water sensitive clays Primary spending. This is the damage removal step. Same as classical theory. Secondary spending. Dissolved silicon will re‐precipitate as Si(OH)4. Tertiary spending. Aluminum leaching, leaving Si(OH)4. Potential Al scaling Will HCl be spent in clay rich formations Name the most common HF acid systems What are the normally used acid volumes? What is the typical treatment procedure for an sandstone acid treatment Oct-19-15 Yes, but only during secondary and tertiary spending ! 13.5/1.5% HCl/HF High HCl/HF ratio (prevent precip.) ! Retarded HF For deep damage (fines migration) ! 9:1 HCl/HF Low HF, for high feldspar formations ! Organic/HF For higher temps ! 12/3 HCl/HF ‘Mud acid’ for silica scale removal ! HCl only Whenever carbonate content > 10% 100 – 200 gals/ft Mud Clean‐out (whole mud lost) Wellbore Cleanout (pickle tubing) Non‐acid preflush (NH4Cl) 50‐100 gal/ft Acid Preflush (HCl) 50‐100 gal/ft Damage Removal System (HF/HCl) 50‐200 gal/ft Diverter stage Overflush (NH4Cl) 25‐100 gal/ft Displacement What methods are available to obtain the kh in a From a log, or combination of log and core tests well? From a well test (e.g. a buildup) What alternative methods are available to obtain the Well test (build up or fall off). skin in the well? Which method is the most Analyse PI decline over time. Reservoir pressure and kh reliable? are also needed in this method Why is Water NOT a good choice as a Brine Risk of clay swelling Preflush? Which of these two fluids (13.5% HCl/HF or 9/1% HCl/HF) is preferred? Why? 13.5% HCl/HF preferred because it has a higher HF concentration and is therefore more efficient What is the purpose of the Aqueous Non‐acid Preflush (=Brine preflush)? Establish injectivity before pumping acid, spacer between acid and reservoir fluids What is the purpose of the Acid Preflush? Remove carbonates, other (acid‐soluble) material, incompatible with HF What is the purpose of the Acid Mainflush? Dissolve damage (clay fines) In a sandstone acid treatment, what is the major HF acid difference in composition between the Acid Preflush and the Acid Mainflush? What is the purpose of the Non‐acid Overflush (=Brine overflush) Displace spent acid deeper into formation, to prevent potential precipitations in near wellbore What brines are acceptable in HF acidizing? Oct-19-15 Only NH4Cl (ammonium chloride) When would you select coiled tubing to pump an acid treatment? When bullheading? What are the advantages/disadvantages of both methods? What is the effect of pump rate on the final treatment results? Is there a difference between sandstones and carbonates? The bottom hole pressure (BHTP curve) drops rapidly, after the first brine stage (2% NH4Cl) has reached the perforations. Why? Coiled tubing: when tubing is dirty (rust, scale); in longer wellbores (placement) Bullheading: relatively short intervals, high rate pumping In sandstones the effect of pump rate is only small. The main advantage of a higher pump rate is the shorter treatment time In carbonate acidizing, pump rate is important. A higher pump rate will result in longer wormholes and deeper stimulation The viscosity of the injected brine is lower (about 0.4 cp, see Pumping Schedule), compared to the viscosity of the reservoir fluid (about 1.2 cp, see Reservoir Fluid Details screen) The BHTP goes down during the 13.5/1.5% HCl/HF The acid dissolves the damage, reducing the skin. As a stage. Explain! result, the bottomhole pressure decreases during the treatment The skin drops from 10 to about 8, during the 7.5% The 7.5% HCl does not remove the fines damage, but it HCl stage. Explain! will dissolve the carbonate in the mineralogy. This increases the permeability in the near wellbore, and reduces the skin Why is lowering the HCl concentration a good idea? Cheaper, less corrosion and easier to inhibit Oct-19-15 10 ... None, no stimulation candidate 2 mD gas well with a skin of 1 .5 and in which losses occurred during comple5on? An oil well with a high skin in a sandstone forma5on containing streaks of up to 25 % calcite has been damage by mud losses. ... Non‐acid preflush (NH4Cl) 50 ‐100 gal/ft Acid Preflush (HCl) 50 ‐100 gal/ft Damage Removal System (HF/HCl) 50 20 0 gal/ft Diverter stage ... calcite has been damage by mud losses. What is the best type of acid to be used? Which are the four main phases in s5mula5on design? Oct-19- 15 HCl or organic, No HF! • Candidate selection and damage analysis • Fluids and additives recommendation