Sunday, March 10, 2019

Advance Fracturing Fluids Improve Well Economics

The oil and gas industry has witnessed a revolution in fluids technology for hydraulic fracturing. Starting in the mid 1980s, focused research led to major improvements in the performance of well stimulation fluids. Today, new additives and fluids are extending these capabilities and providing innovative solutions to nagging problems. The results are more efficient and cost-effective treatments for enhancing well production.

 Hydraulic fracturing is one of the oil and gas industry's most complex operations. This technique has been applied worldwide to increase well productivity for nearly 50 years. Fluids are pumped into a well at pressures and flow rates high enough to split the rock and create two opposing cracks extending up to 1000 ft [ 305 m] or more from either side of the borehole. Sand or ceramic particulates, called proppant, are carried by the fluid to pack the fracture, keeping it open once pumping stops and pressure decline.

What defines a successful fracture? It is one that: 

  • is created reliably and cost-effetively
  • provides maximum productivity enhancement 
  • is conductive and stable over time.  

The Rock, the mechanics and the Fluid

Historically, fracturing has been applied primarily to low-permeability- 0.1 to 10 md-  formations with the goal of producing narrow, conductive flow paths that penetrate deep into the reservoir. These less restrictive linear conduits replace radial flow regimes and yield a several-fold production increase. For large-scale treatments, as many as 40 pieces of specialized equipment, with a crew of 50 or more, are required to mix, blend and pump the fluid at more than 50 barrels per minute (bbl/min). Pumping may last eight hours with 1,000,000 gal of fluid and 2,000,000 to 4,000,000 lbm of propant placed in the fracture.

Until recently, treatments were performed almost exclusively on poor producing wells (often to make them economically viable). In the early 1990s, industry focus shifted to good producers and wells with potential for greater financial return. This, in turn, meant an increased emphasis on stimulating high-permeability formations.

The major constraint on production from such reservoirs is formation damage, frequently remedied by matrix acidizing treatments. But acidizing has limitations, and fracturing has found an important niche. The objective in highly permeable foormations is to create short, wide fractures to reach beyond the damage. This is often accomplished by having the proppant bridge, or screen out, at the end, or tip. of the fracture early in the treatment. This "tip screenout" technique is the opposite of what is desired in low-permeability formations  where the tips is ideally the last area to be packed.

 Why the different approach? The answer is found in the relationship between fracture length and the permeability contrast between the fracture and the formation. Where the contrast is large, as for low-permeability reservoirs, longer fractures provide proportionally greater productivity. Where the contrast is small, as in high-permeability formations, greater fracture length provides minimal improvement. Fracture conductivity is, however, directly related to fracture width. Using short- about 100-ft [30 m] - and wide fractures can prove beneficial.

High-permeability formation treatments are on a far reduced scale. Only a few pieces of blending and pumping equipment are required, and pumping times are typically less than one hour, and often only 15 minutes. Fluid is pumped at 15 to 20 bbl/min with a total volume of 10,000 to 20,000 gal and total proppant weight of about 100,000 lbm. This technique has been successful in the North Sea, Middle East, Indonesia, Canada and Alaska, USA.

While fracturing treatments vary widely in scale, each requires the successful integration of many disciplines and technologies, regardless of reservoir type. Rock mechanics experiments on cores, specialized injection testing and well logs provide dat on formation properties. Sophisticated computer software uses these data , along with fluid and well parameters, to simulate fracture initiation and propagation. These results and economic criteria define the optimum treatment design. Process-controlled mixing, blending and high-pressure pumping units execute the treatment. Monitoring and recording devices ensure fluid quality and provide permanent logs of job results. Engineers tracking the progress of the treatment use graphic displays that plot actual pumping parameters against design values to facilitate real-time decision making. Production simulators compare treatment results with expectations, providing valuable feedback for design of the next job.

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