3500m_Acid_Frac酸压案例分析.doc

Acid Fracture Case History2500m LimestoneThe following discussion looks at creating a StimPlan data set for a fracture acidizing application, simultaneously reviewing the considerations that went into selecting acid fracturing as the appropriate stimulation procedure, and the considerations that led to the final design. A basic formation description includes: Lithology“0” Porosity, “Tight” Limestone“Pay” 20+m vuggy LimestoneShale Permeability5+ mdReservoir Temperature280 F (138 C)Porosity 20+ % Natural FracturingModerate to None Thickness20m Depth 3,500m Reservoir FluidOil m 5 cpDetail wellbore data is included in the StimPlan file 3500m_Acid_Frac_Start.STP (and log data is included in 3500m_Acid_Frac.LAS). General Design Considerations Figure 15 Potential Post-Acidizing Well ProductivityFirst, since the formation is carbonate, possibly with some natural fracturing acidizing should automatically be considered. This is particularly true given a moderate permeability of 5+ md. Based on this permeability, the StimPlan FOI (Folds-of-Increase)/PI calculations (Figure1) show a relative short fracture of 20 to 30m significantly increases production. However, if sufficient conductivity can be achieved, then a longer fracture of maybe 80 to 100m ( length) can increase PI by another factor of 1.7X. Also, since the overlying formation is limestone (thus, not shale), there may be less potential for height confinement. Finally, there is some concern about a water productive zone about 18m below the pay, thus downward fracture growth is a major concern. This formation appears to be a candidate for acid fracturing due to: 1) A “Long” fracture is NOT required, 2) Some potential for significant natural fracture permeability, 3) Formation is 100% limestone, and 4) Some concern about downward height growth. Geomechanical Input Figure 16 Basic Geomechanical Input The basic geomechanical data is input in the Geologic Layering dialog (Figure2). The shale/shaly layers are expected to have slightly higher stress, with little stress difference between pay, and the overlying low porosity limestone. Values for modulus were from a normal BHC Sonic log. Finally, note that subsequent “Final Design” or “Pressure Analysis”, the “Detailed Fluid Loss” should pro- subsequent “Final Design” or for any pressure analysis, the “Detailed Fluid Loss” option should probably used. This is due to the formation description as “vuggy”, possibly meaning a significant increase in the “near fracture” loss (i.e., wormhole). Ultimately, the “Detail Fluid Loss” option should be used (at least as a check) for this case. However, for preliminary design purposes, it is acceptable to use “normal” 1-D (“Carter”) fluid loss. The appropriate values of fluid loss coefficient(“C”, ft/min) were calculated using the StimPlan “Help” screen seen in Figure3. This gives a value of about 0.0035 ft/min. The lower (water0 limestone was then set at a fluid loss value of 0.0017. Figure 17 Calculating Expected Fluid Loss Acid Reactivity At this relatively high formation temperature (280 F, 138 C), acid reactivity is expected to be high, such that it paradoxically becomes unimportant, i.e., acid diffusion or mass transport behavior determines acid spending. Since reaction rates are not expected to be or major importance, default values are used as seen in Figure4. Figure 18 Inputs for Formation Acid Reactivity Acid Fluid Data Finally, data for straight as (15% HCl and a 13%/9% mixture of Acetic and Formic, are input in Figure5. The wellbore temperature values for Diffusion Coefficient were taken from service company handbook data, while the reservoir temperature values came from specific laboratory testing. Figure 19 Acid Fluid Input DataPump Schedule Figure 20 Acid Pump Schedule The first step in the design process is to consider a simple acid injection. A simple pump schedule is created as seen in Figure6. This is then simulated using the “Fully 3D” simulation (since fracture geometry is expected to be more or less “radial” (i.e., tip-to-tip length about equal to fracture height). Figure 21 15% HCl Injection (100 m3 2 m3/min)Net Pressure Behavior Final Conductivity Acid Etched Width 20 min Acid Etched Width 33 min Results from this first simple simulation are summarized in Figure7. This shows an etched fracture length of about 40m after 20 min of pumping, with essentially no additional etched length at the end of the injection at 33 minutes. Thus, while the acid reaction is mostly confined to the pay, fracture height growth is preventing the creation of fracture length. The final acid etched conductivity is also seen in the figure. Additional simulations must now be done considering organic acid. Maybe higher pump rate and/or the use of pad-acid techniques (i.e., following the first acid injection with a viscous pad, then additional acid, etc., and/or considering the use of gelled/emulsified acid. Power of “Fully 3D” Simulations Note that an injection of simple (low viscosity) acid has resulted in massive height growth, with little etched penetration. However, the etched width is concentrated in the high porosity, high fluid loss “pay”. Maybe one can take advantage of this situation? Would a stage of viscous gel fill the entire fracture, and then subsequent low viscosity acid stages might preferentially flow where the width is greatest (where acid etching has been concentrated in the pay)? Figure 22 Acid/Pad/Acid Acid Etched Width A simple treatment was formulated as seen in Figure8, consisting of acid-gel-acid-gel-acid. Note th