The majority of current activity in shale reservoirs involves the use of horizontal wells and most reservoirs are also hydraulically fractured in the completion process. The hydraulic fracturing process has evolved rapidly in the last decade and techniques most common in the early days of hydraulic fracturing have largely been replaced by several new concepts. While these are no doubt going to be replaced by newer techniques, the reservoir engineer must understand hydraulic fracturing and completions, as the measurement of the stimulated volumes is likely to be strongly related to drainage areas.
In the late 1980s through early 1990s, horizontal drilling technology evolved to the point that horizontal wells were routinely being used in three primary applications, viz.
• naturally fractured reservoirs,
• thin reservoirs with relatively high productivity, and
• reservoirs with good vertical permeability and fluid contacts that resulted in coning (usually oil/water but also gas/oil and gas/water contacts).
While early attempts to use horizontal wells in conventional tight gas systems had erratic and often uneconomic results, the potential to replace multiple vertical wells with a single horizontal well with multiple fractures was identified as a significant opportunity by many operators. Of the three major early applications, the use of horizontal wells in naturally fractured reservoirs was the most obvious candidate for hydraulic fracturing. While there were a significant number of horizontal wells completed in naturally fractured reservoirs that were not hydraulically fractured, hydraulic fracturing has become commonplace in such reservoirs.
The Austin Chalk was the first large scale application of horizontal wells in naturally fractured reservoirs with thousands of horizontal wells being drilled in an area that had been drilled (and ostensibly depleted) by many thousands of vertical wells. The application of “water fracs” in Austin Chalk vertical wells were largely repeated fracs at a later stage in a well’s life following significant production. Most vertical wells in the Austin Chalk had been completed with conventional hydraulic fracturing or acidizing. The “water fracs” for vertical wells involved modest volumes of water at relatively high rates (typically 15-30 MBW at 75 bbl/minute).
These fracs were inspired by so called ‘river fracs’ typical of the Mississippian limestone treatments common in northwestern Oklahoma in the late 1970s. These jobs were in thick vertical sections with staging achieved by placing frac baffles that would serve to isolate the stages. The lower most perforations (below the bottom baffle) would be perforated with wireline conveyed tubing guns and the first stage of the frac job would be pumped. A ball of a diameter small enough to pass through upper baffles but large enough to land on the baffle above the recently pumped job would then be dropped. The next stage would be perforated and fracture treated and another ball dropped until the desired stages had been pumped.
While many Austin Chalk vertical wells were treated with conventional gelled jobs or large acid jobs, the refracturing campaigns of the 1980s focused on water fracs. These Austin Chalk vertical well water fracs resulted in significant production increases and lead to their application in thousands of horizontal wells. Typical completion practices for the Austin Chalk drilling in the 1990s involved either open hole completions or uncemented liners (either pre-drilled, slotted or preperforated). Meehan (SPE 1995 production & Facilities) describes typical jobs where rates could be as high as 300 bbl/minute. While diverters were used in many wells, few operators attempted multiple, isolated hydraulic fractures in horizontal wells.
As more horizontal wells were drilled in formations requiring hydraulic fracturing, several common themes were identified in formations ranging from the Cotton Valley of East Texas to the North Slope of Alaska to the Dan Field in the North Sea. It became clear that successful hydraulic fracturing in horizontal wells depended on a number of common variables. First, the orientation of the horizontal well with respect to the horizontal compressive stresses. Wells drilled from a central pad or platform realized the lowest treating pressures when the horizontal portion of the well was either parallel to or perpendicular to the minimum horizontal compressive stress. Wells drilled at angles intermediate to these directions often resulted in screenouts and certainly in higher treating pressures. Similarly, successful wells in cased, cemented horizontal wells tended to perforate very short intervals (less than 3 feet) per stage.
Many operators recognized the need for better staging of the hydraulic fracturing treatments allowing better placement and coverage. Cased and cemented wells accomplished both of these objectives but at very high costs. Such jobs required a great deal of rig time, having the rig on location during and after the frac job and costly tools. Besides the long string of casing to negotiate hole curvature, there are always challenges in cementing long horizontal sections. It is difficult to achieve centralization of casing and even in centralized pipe it is difficult to achieve good hole cleaning and placement of cement with rugose holes and occasional variations in hole angle. As cement sets, placement may diminish in quality radially around the wellbore. Because it is important to only perforate a few small intervals, multiple runs with tubing conveyed or drillpipe conveyed perforating guns may be necessary. Alternative technologies for deployment of perforations do exist and include tractor-type devices, knock out plugs in casing (pre-installed perforations blocked with a material that can be removed by physical contact, acid soluble plugs, etc. Perforations in horizontal wells placed near the bottom of the well may be useful for stimulation but are likely to fill with production debris. Finally, cased and cemented wells often cause significant formation damage; this is particularly the case in naturally fractured reservoirs. Numerous advances have enabled operators to dramatically lower completion costs in horizontal, hydraulic fracturing wells. These approaches have become de facto standards in shale reservoirs.
Perf-n-plug refers to a technology that allows an operator to rapidly perforate, stimulate and produce multiple stages. Although applicable in vertical and deviated wells, most shale applications are for nearly horizontal wells. The perf-n-plug approach can be used in wells with cemented or uncemented liners. In horizontal wells in the past, it was necessary to use technology such as tubing conveyed or coiled tubing conveyed perforating guns for perforations in order to convey the perforating tool to the correct location without the aid of gravity. It is now common to use wireline conveyed guns by pumping the guns down the hole (the plug, run in tandem with the guns, has an OD near the ID of the casing, and the assembly is pumped to the correct location in the well). The pump down approach is used in both cemented and uncemented liners and significant volumes of water or frac fluid may be lost to the formation.
After the perforations have been placed the first hydraulic fracturing treatment is conducted. Another composite plug is then placed in the wellbore above the top perforation of the prior stage. Composite plugs are designed to set easily and to hold the high differential pressures associated with hydraulic fracturing. They must also be made of a material that is easily drillable. Different materials enable the plugs to withstand variable temperatures and pressures. In a typical configuration the composite plugs are conveyed on wireline or coiled tubing. Composite plugs can serve as bridge plugs (isolating each stage in both directions and requiring retrieval to enable production from lower zones. More common applications include poppet style frac plugs that function as one way check valves (enabling flow from lower zones up the wellbore but preventing backflow) and ball type frac plugs. Ball type composite plugs use a ball dropped from surface to seat on the plug holding pressure from above while allowing flow from below. Most shale applications use the ball type plug. In a given stage the plug is set, perforations above it are placed, the ball is dropped (resulting in a pressure spike) and the frac job is pumped. After this has been repeated as many times as necessary, the composite plugs are milled up and the well can be produced.
Typical perforation intervals include a few short (less than 1 m.) intervals within the interval between plugs. It is critical to perforate short intervals to avoid multiple fracture initiations. Multiple simultaneous adjacent fractures competing for fluid result in small widths and larger shear components. This may lead to very high near wellbore pressure drops and screenouts. Most (if not all) of the fracture fluid placed in such a stage would be in the initial fractures opened; subsequent fractures opened with sand laden fluid unlikely to propagate far. Even if not all of the perforations result in hydraulic fractures, production into the wellbore can nonetheless enter the well from each of the perforation intervals. In naturally fractured reservoirs or other permeable applications it may be appropriate to add perforations after the fracture treatment.
With uncemented liners it is unlikely that the perf-n-plug method results in the same level of control over the location of fracture initiation that can be obtained with cemented liners. The perforation of an open hole does not ensure fracture initiation at that point. The detailed mechanics of where and how fractures initiate is not covered in this book, but suffice it to say that it is not easily predicted with certainty.
The need for advanced hydraulic fracturing completions in shales has generated new technology that enables operators to fracture dozens of individual stages with back-to-back fracture stimulation jobs. These open hole packer completion systems minimize total “spud to sales” time by placing a series of packers and sleeves in the well and allowing the rig to move off prior to fracturing. The open hole packer completion approach eliminates the need for cementing and perforating and can be used as the primary fracturing system or in refrac applications. The tools can be rotated going in hole which is important for laterals with large dogleg severity and multilaterals. The deployment of the open hole packer completion system often uses reactive element packers but can be deployed with hydraulically set packers. Between the packers are sleeves that can be actuated to selectively allow fluid entry by stage. These are typically actuated by balls that are pumped down following each stage.
In applications where varying diameter balls are used, there may be a practical limit to the number of stages that can be pumped using solely the open hole packer completion systems. It is certainly a number in excess of two dozen. However, open hole packer completion systems may in fact be combined with perf-n-plug for the final stages allowing a large number of stages to be pumped. Optimizing the actual number, size and placement of stages is the responsibility of the reservoir and completion engineers.
Reactive element packers do not require wellbore or casing/liner contact in order to initiate the setting process. The packer rubbers swell in the presence of the appropriate fluid, either water or oil; RE packers are also referred to as “swell” packers. This swelling is designed to be a one-way process and a subsequent change in the type of fluid present will not reverse the swelling process.
RE packers eliminate the cost and formation damage associated with cementing and do not require complex running tools. They are conveyed on tubing and can be placed with a high degree of accuracy. If required because of extensive wellbore instabilities, image logs can be used to identify competent hole sections to ensure setting.
The perf-n-plug completions and open hole completion systems are each widely used. The following table summarizes some of the relative strengths of each approach. The specific application will determine which technique is preferable.
1 A screenout occurs in hydraulic fracturing when it is no longer possible to pump fluids into the well. This usually happens with proppant laden fluids and occurs either when proppant laden fluid reaches the tip of the fracture (a “tip screenout”) or, more commonly when high levels of near wellbore pressure occur. Sources for such high near wellbore pressure are many and include tortuosity, multiple open fractures competing for fluids, large shear components to the created fracture (such as turning into the direction of far-field stresses), etc. Fracture designers often try to achieve tip screenouts, particularly for small fracture treatments in high permeability formations. Achieving tip screenouts in tight gas wells is more controversial and most screenouts in such formations are likely to be near wellbore screenouts.