Method for Increasing Productivity of Hydraulically Fractured Wells
Method is provided for increase production rate and improving economics of hydraulic fracturing of a well where a fracture can be formed extending a greater distance than the thickness of the pay zone in the well. A settling fluid containing proppant is injected to form a bank or pile of proppant that extends beyond the pay zone.
1. Field of the Invention
This invention relates to hydraulic fracturing of wells. More specifically, method is provided for increasing the flow capacity of a hydraulic fracture around a well (Fracture Flow Enhancement), thereby increasing the value of the well.
2. Description of Related Art
Hydraulic fracturing is an established technology that has made possible recovery of hydrocarbons from wells that would not be economic to drill without the availability of the fracturing process. It has also improved the economics of gas and oil recovery operations in many other wells.
After a well is drilled to a pre-determined depth to penetrate one or a series of pre-determined “pay” formations (formations containing producible hydrocarbons), pipe (casing) is inserted into the drilled hole, and then cement is placed at pre-determined intervals in the annular space between the outside of the pipe and the drilled hole; the cement is placed for the purpose of preventing flow of fluids in the penetrated formations from entering the wellbore or flowing between formations.
If the pipe is adjacent to (passes through) one or more pay formations, methods are then employed to create communicative flow paths from the pay zones to the wellbore. These methods may be applied on a single pay or several of them. They are done by creating openings (perforations) in the pipe and the cement adjacent to the pay and that penetrate into the pay. There are several well known methods used to create these perforations.
After the above processes are completed, it is a common practice to hydraulically fracture the well. This process has been used in the oil and gas industry since the late 1940's. The hydraulic fracturing process involves injecting a fluid (liquid, foam, gas, etc.) to create a fracture in a subsurface geological formation that contains the pay. At some time during the process a proppant is blended with the fluid to create slurry, such that the slurry extends the fracture penetration (both laterally and vertically), transports the proppant into and along the fracture, and out to some distance away from the wellbore. The fluid in the slurry is designed such that when the slurry injection is stopped, the fluid leaks off into the pores of formations adjacent to the fracture and the fracture walls close on the proppant. The proppant is left in the fracture to hold the fracture open and form a highly conductive path to allow oil or gas to more easily flow from the extremities of the pay into the well. Normal practice is to place proppant over the pay zone.
The determination or design of how much of what fluid and how much of what proppant and the injection rate required for a treatment depends on a priori knowledge of (1) the profile of in situ properties of the formations that control the geometry (dimensions and shape) of the propagating fracture, and (2) the permeability of the pay, which impacts the required fracture size and fracture conductivity required to achieve a desired production folds-of-increase from the treatment. Knowledge of the profile of in situ properties of a formation is typically ascertained using down hole well log surveys, from which formation lithologies and the mechanical rock properties (such as formation Poisson's Ratios and Young's Moduli can be interpreted.
Stress profiles, which impact vertical fracture height, are routinely calculated from Poisson's Ratios. Fracture widths, which impact fracture conductivity, are impacted by both in situ stress and Young's Modulus. Hence, knowledge of these properties is essential in the credible design of a fracturing treatment. These treatment designs are typically done using a computer model to calculate the treatment design required to arrive at a required fracture penetration geometry and required fracture conductivity which will yield a desired production folds of increase (FOI).
The required fracture conductivity is typically ascertained from well established approaches that incorporate fracture conductivity with formation permeability, pay thickness, and fracture penetration length to calculate production folds-of-increase (FOI). These are documented in described in the Society of Petroleum Engineers, Monograph, Volume 12: Recent Advances in Hydraulic Fracturing, by John L. Gidley, Stephen A. Holditch, Dale E. Nierode, and Ralph W. Veatch, Jr., Copyright 1989, ISBN 1-55563-020-0.
All approaches have the commonality that the calculated production FOI results are normalized on net pay thickness. That is the approaches assume that the fracture conductivity is effective only over the pay thickness. Hence, because of this assumption, it is atypical to design a fracturing treatment where more proppant is used than is required to cover the pay, the reason being that the well-established production FOI calculations do not make the benefits apparent for increasing fracture conductivity beyond the extent of the net pay. Normally fracture treatments are not intentionally designed to have settled proppant packs that extend significantly above the top of the pay. Normally designs are for the settled proppant pack to at least reach the top of the pay, and usually not extend more than one-half of the pay thickness above the top of the pay. In the prior art, if proppant packs were designed to extend above the pay, by any amount, it was to ensure that the entire pay was covered, rather than to achieve a benefit from additional fracture conductivity.
Herein lies the novelty of this invention. It addresses the benefits of increasing fracture conductivity beyond the extent of the pay. The method for doing that is to design treatments with sufficient proppant volumes to create additional fracture conductivity beyond the extent of the pay.
Although improvements in proppants have been made by providing higher strength proppants, such that the flow conductivity of fractures has been increased, there is still a need for hydraulic fractures around wells that allow higher flow rates of fluids at given pressure conditions in and around the well.
BRIEF SUMMARY OF THE INVENTIONMethod is provided for forming a proppant pack in a fracture around a well that makes possible higher flow rate into the well by increasing the vertical height of the proppant pack beyond the pay zone to be produced.
The preceding figures, along with the corresponding discussion constitute the Base Case scenario that is used as a basis for comparison with the Fracture Flow Enhancement (FFE) process disclosed herein.
Some fracturing fluids have high viscosity at reservoir conditions and transport proppant for long distances away from a wellbore. The proppant may not settle for a significant distance in the fracture before the fracture closes. In this case, if the fracture extends above or below the pay zone, the proppant will be left above or below the pay zone in the fracture. Other fracturing fluids have low viscosity in the fracture and allow proppant to settle to the bottom of the fracture during pumping or before the fracture closes (herein “settling fluid”). Most or all the proppant is then located in a proppant pack at the bottom of the fracture, and the width of the proppant pack in the fracture is near the width of the fracture. Normally, the quantities of materials (fluid and proppant) used in fracturing processes are designed to create conductive fractures that cover the vertical extent of the pay and that do not extend significantly beyond the pay into formations above the top of the pay. In many cases, when a settling fluid is used the vertical extent of the proppant pack may not exceed ten percent of the pay thickness.
The vertical extent of a fracture is limited by variations of stress in the earth. Pay zones typically have lower horizontal earth stress and shale or impermeable zones have higher stress. The higher stress zones limit the vertical height of a hydraulic fracture.
When a predicted stress profile in a well is obtained, a hydraulic fracturing treatment may be designed to form a fracture having a selected height, which depends on the stress profile as well as the properties of the fracturing fluid and the pumping rate during the treatment. For example, using the stress profile of
Using the method disclosed herein, where the vertical extent of the fracture exceeds the vertical extent of the pay, the top of the proppant pack in the fracture, in the vicinity of the wellbore can be controlled. If the vertical extent of the fracture is significantly larger than that of the pay, a treatment may be designed to have a settled proppant pack that extends well above the pay. This would provide additional fracture conductivity for fluids to flow to the wellbore. Normally fracture treatments are not intentionally designed to have settled proppant packs that extend significantly above the top of the pay. Normally designs are for the settled proppant pack to at least reach the top of the pay, and usually not extend more than one-half of the pay thickness above the top the top of the pay. However, the vertical extent of the top of the proppant pack in the fracture is limited only by the upward vertical extent of the fracture. This disclosure is to take advantage of opportunities where it is possible to create proppant packs with vertical extents well beyond the pay interval (above it, or below it, or both) so as to provide more fracture conductivity, and thus increase the flow rate from the pay to the wellbore.
Normally, connections from the wellbore to the fracture do not extend significantly beyond the extremities of the pay, either above it or below it more than one-tenth the thickness of the pay interval. There may be portions of the pay that overlie and/or underlie intervals that are considered “economical pay,” but are not connected for economical reasons. There may be portions of the pay that overlie and/or underlie intervals that are considered “economical pay,” but are not connected for other reasons—for example water or gas bearing intervals that may constitute undesirable consequences if they are connected. Such intervals are not considered as pay intervals, for whatever reason, by those associated with the well.
Using the method disclosed herein, connections from the wellbore to the fracture extend more than ten percent beyond the vertical extent of the pay; either above it, below it, or both above and below it. The fracture conductivity, producing rate, total production, and monetary benefits of the Fracture Flow Enhancement (FFE) process disclosed herein derive from either one or both of the following:
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- (1) increasing the conductive path for fluids residing in the entirety of the pay to travel through the fracture to the wellbore.
- (2) connecting the wellbore to the fracture above and below the pay, so as to increase the flow from the pay into the wellbore.
An example is included to demonstrate the procedure, and the potential production and monetary benefits of the procedure. Computer programs were used to generate the example. These programs are the property of Software Enterprises, Inc., of Tulsa, Okla. They comprise the fracturing technology described in the Society of Petroleum Engineers, Monograph, Volume 12: Recent Advances in Hydraulic Fracturing, by John L. Gidley, Stephen A. Holditch, Dale E. Nierode, and Ralph W. Veatch, Jr., Copyright 1989, ISBN 1-55563-020-0 R. W., 1988. They are provided to participants in hydraulic fracturing industry schools taught by the Ralph W. Veatch, Jr., and are publically available, at a fee, upon request to Software Enterprises, Inc. The example is for a typical oil well, producing from a 100 foot thick pay that lies at a depth between 7400 and 7500 feet. The formation intervals above 7100 feet and below 7525 feet impose significant vertical fracture growth inhibition. It was predicted that a fracture extending 560 feet vertically can be produced by pumping 846,000 gallons of aqueous, borate cross linked, 35 lb/1000 gallon guar polymer fluid at a rate of 30 barrels per minute. This fracturing procedure thus allows placement of proppant in a fracture extending significantly outside the pay zone.
The formation properties, mechanical rock properties, in situ stress profile, pipe, connection, cost, oil price ($65/bbl), taxes (15%), royalties (⅛), operating costs ($1000/month), etc., data used for the example came from actual field cases, but the sources are not confined to those of a particular well. The fracturing material property and behavior data used are commensurate with current fracturing design and prediction practices.
For this example, the well is identified as the 17.8.1 well. The results and predictions generated for the 17.8.1 well base case scenario by the computer models are posed as ground truth for comparing the base case scenario to the FFE scenario to demonstrate the potential benefits derivable from FFE.
The Base Case
Table I contains base case propping agent (proppant) data for the four types of proppants used in the example. The symbol kfwf represents the fracture conductivity of the proppant pack at the various conditions shown. The in situ values are those used in the computer calculations.
Table 2 shows a summary of the predicted fracture penetrations, fracture vertical heights, average fracture widths, material requirements, material costs, total fracturing costs, net present value returns and discounted returns on investments for the four proppants used in the study. These are shown for four fracture penetration lengths.
The preceding figures, along with the corresponding discussion constitute the base case scenario that is used as a basis for comparison with the FFE.
The Fracture Flow Enhancement (FFE) CasesThese are predictions for three scenarios of the FFE:.the first is where the top of the proppant pack is at the top of the pay, the second is where the top of the proppant pack is 100 feet above the top of the pay, and the third is where the top of the proppant pack is 200 feet above the top of the pay in the first scenario, the connections from the wellbore to the fracture are equivalent to the pay. In the second and third scenarios, the connections extend to or beyond the vertical extent of the fracture, to assure that there is a connection between the fracture and the wellbore. All parameters in the Base Case scenario are used in the FFE scenarios except for those changed for the parametric studies in the FFE scenarios. In all three scenarios, the fracturing fluid quantity requirements are equivalent. The total amount of fluid is the same for the base case and the three scenarios. The fracture geometry is governed primarily by the in situ stress and mechanical rock properties and the rheological behavior of the slurry injected. Studies by the applicant have indicated that changes in the proppant quantities injected do not alter the results to any degree of significance from the base case scenario. These proppant quantities are obtained, or controlled, by adjusting the proppant concentrations of the injected slurry.
In view of the results, as shown the example, application of the FFE concurrently with fracturing processes offers the potential of increasing enhancement of the fracture conductivity in, the producing flow rate from, the total production from and the monetary returns from a well.
Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.
Claims
1. A method for hydraulic fracturing of a well penetrating a pay zone, the pay zone having a thickness, comprising:
- injecting a fluid to create a vertical fracture extending a vertical distance equal to or greater than twice the thickness of the pay zone; and
- injecting a settling fluid containing a proppant to form a settled bank of proppant that extends in the vertical fracture over a vertical distance that is greater than about one and one-half (1½) times the thickness of the pay zone.
2. A method for hydraulic fracturing of a well using a Fracture Flow Enhancement treatment, the well penetrating a pay zone having a thickness, comprising:
- using measured or estimated properties of rock around the well, predicting the vertical extent of a hydraulic fracture using selected properties of fracturing fluids and fracturing pumping conditions;
- injecting a fluid under selected conditions to create a vertical fracture extending a vertical distance greater than twice the thickness of the pay zone; and
- injecting a settling fluid containing a proppant to form a settled bank of proppant that extends in the vertical fracture over a vertical distance greater than one and one-half (1½) times the thickness of the pay zone.
Type: Application
Filed: Jan 4, 2012
Publication Date: Jul 12, 2012
Inventor: Ralph W. Veatch (Tulsa, OK)
Application Number: 13/343,111
International Classification: E21B 43/26 (20060101);