US20120175121A1

US20120175121A1 - Method for Increasing Productivity of Hydraulically Fractured Wells

Info

Publication number: US20120175121A1
Application number: US13/343,111
Authority: US
Inventors: Ralph W. Veatch
Original assignee: Individual
Current assignee: Individual
Priority date: 2011-01-06
Filing date: 2012-01-04
Publication date: 2012-07-12

Abstract

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.

Description

BACKGROUND OF INVENTION

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.
FIGS. 1( a), (b) and (c) depict three typical sketches of current practices for inserting casing, cementing and perforating wells. In FIG. 1( a), casing penetrates the entire pay zone. In FIG. 1( b), casing only partially penetrates the pay zone. FIG. 1( c) illustrates an open hole completion, where the pipe does not penetrate the pay zone, or much of it (often referred to as a “topset” completion).
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 INVENTION

Method 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.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S)

FIGS. 1( a), (b) and (c) are sketches of current practices for placing casing or leaving an open hole for well completions.

FIGS. 2( a), (b) and (c) illustrate in situ stress, Poisson's ratio and elastic modulus magnitudes versus depth for a base case illustration.

FIGS. 3( a), (b) and (c) depict the in situ stress profile versus depth, along with the fracture half-width versus depth profile for the base case, where the fracture penetration length, Xf, has reached a distance of 1190 feet from the wellbore. The Xf versus depth profile is artistic license, for the sake of differentiating it from other lines in the figure. The computer generated fracture vertical height value is that shown where the fracture intersects the wellbore at Xf equals 0 feet, and the height remains constant from the wellbore to Xf equals 1190 feet.

FIG. 4 shows base case proppant requirements vs fracture penetration.

FIG. 5, shows base case predicted folds-of-increase of production rate vs fracture penetration.

FIG. 6 shows base case predicted pre- and post-frac production vs time as predicted for each of the proppants; for this depiction all values are for an Xf equal to 1190 feet.

FIG. 7 illustrates base case present value increase vs fracture penetration.

FIG. 8 shows base case fracturing costs vs fracture penetration.

FIG. 9 shows base case npvf vs fracture penetration.

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.

FIG. 10( a) shows calculated fracture half-width vs depth for a proppant pile at the top of pay when the fracture penetration length, Xf, has reached 1190 feet. FIG. 10( b) shows fracture length vs. depth. Again, the Xf versus depth profile is artistic license; the computer generated fracture vertical height value is that shown where the fracture intersects the wellbore at Xf equals 0 feet, and the height remains constant to Xf equals 1190 feet. Also shown are the vertical extents of the pay, the vertical extent of the wellbore connection to the pay and the proppant pack top is at the pay top. In FIG. 10, the connections from the wellbore to the fracture are equivalent to the pay.

FIG. 11 shows a proppant pile 100 ft above the top of pay.

FIG. 12 shows a proppant pile 200 ft above the top of pay.

FIG. 13-A shows the change (increase/decrease) in proppant quantity requirements vs proppant pile above or below the top of pay. FIG. 13-B shows the change (increase/decrease) in proppant costs vs proppant pile above or below the top of pay.

FIG. 14 shows the predictions for percent change from the base case scenario in production rate folds of increase (FOI) for proppant packs that range from 20 feet below the top of the pay to 180 feet above the top of the pay.

FIG. 15 shows the change in NPVJ vs proppant pile above or below the top of pay.

DETAILED DESCRIPTION OF THE INVENTION

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. FIG. 2( a) illustrates stress vs depth in a well and the pay zone of the well (determined by electric or other logs). Sonic logs of the well are used to calculate Poisson's Ratio (FIG. 2( b)) and Young's Modulus (FIG. 2( c)) of rock around the well, from which stress and fracture width are is calculated. 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.
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 FIG. 2( a), which is the same in FIG. 3( a), a fracturing treatment may be designed that extends a considerable vertical distance above the pay zone. Using a settling fluid for the treatment, and by controlling the total quantity of proppant injected, the vertical extent of the proppant pack can be controlled.
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:

- (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.

EXAMPLE

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

FIGS. 2( a), (b) and (c) illustrate the base case in situ stress & rock property profiles that are used to illustrate the principles of the invention disclosed herein. FIG. 2( a) shows in situ stress, FIG. 2( b) shows Poisson's ratio and FIG. 2( c) shows elastic modulus magnitudes versus depth. These are properties that govern the fracture geometry as it propagates both laterally and vertically into the formations.
FIG. 3( a) depicts the in situ stress profile, FIG. 3( b) the fracture half-width versus depth profile and FIG. 3( c) the penetration length distance (1190 feet) from the wellbore (which is denoted by the symbol Xf in this and subsequent figures). The Xf versus depth profile is artistic license, for the sake of differentiating it from other lines in the figure. The computer generated fracture vertical height value is that shown where the fracture intersects the wellbore at Xf=0 feet, and the height remains constant to Xf=1190 feet.

TABLE 1

Conductivity TEST Data: @ 5,030 psi In Situ Stress & 150° F.

Pack

In Situ Effective

Proppant		Prop		Width		Cond.	Perm.
Description:		Conc.	KfWf	Wf@C	%	KfWf	Kf
Size/Type	SpGr	lb/ft²	md-ft	in	Dam'g	md-ft	Darcy's

20/40 Ottawa Sand	2.65	3.00	2900	0.346	95.0%	145	5
20/40 Resin Coated Sand	2.55	3.00	4800	0.360	90.0%	480	16
20/40 Int. Density	3.20	3.00	6000	0.287	90.0%	600	25
20/40 Sintered Bauxite	3.58	3.00	6500	0.256	85.0%	975	46

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.
FIG. 4 shows the proppant quantities required for four proppants and concentrations indicated in the figure as the fracturing procedure extends fracture penetration to lengths Xf.
FIG. 5 shows the predicted production folds-of-increase (FOI) that would result for the fracture penetrations of Xf. FOI represents the ratio of post-fracturing producing rate to pre-fracturing (not-fractured) producing rate for the same four proppants and concentrations.
FIG. 6 shows the pre-fracturing producing rate decline over time and the post-fracturing producing rates over time as predicted for each of the proppants.
FIG. 7 shows the increase in present value, at 15% discount rate, of production from the well for different values of fracture penetration for each of the proppants.
FIG. 8 shows the material and pumping cost requirements as the fracturing procedure extends fracture penetration to lengths Xf for each of the proppants.
FIG. 9 shows the predicted net present value (NPVf) at 15% discount rate, of production from the well that would result from fracture penetrations of Xf. NPVf represents the discounted value of the production flow stream over time after the fracturing costs, production taxes, royalties and operating costs have been subtracted from the production income. The fracturing treatment data pertinent to FIG. 9 are contained in TABLE 2

TABLE 2

			Prop

Fracture Geometry

Fluid

Prop

Quantity

Fracturing Costs

Net Returns

Xf	Hf	Wfp	Vol	Conc	M-Lbs	Fluid	Prop	Pmp/Fxd	Tot	NPVf
ft	ft	In	M-Gal	ppg	% Hf Adj	(MS)	(MS)	(MS)	(MS)	(MS)	DROI

20/40 Ottawa Sand: 2.65 sp.gr., & L.T. - Kf = 5 Darcy's @ 3.0 lbs/sqft

300	480	0.42	100	6.3	165	77	19.8	42.0	138	8751	63.2
600	511	0.36	213	5.7	299	163	35.9	42.0	241	9528	39.5
890	536	0.40	442	5.1	525	339	63.1	45.2	447	9559	21.4
1190	560	0.44	846	4.4	835	649	100.3	45.2	794	9423	11.9

20/40 Resin Coated Sand: 2.55 sp.gr., & L.T. - Kf = 16 Darcy's @ 3.0 lbs/sqft

300	480	0.42	100	6.1	159	77	74.7	42.0	193	17834	92.2
600	511	0.36	213	5.5	288	163	135.2	42.0	340	19623	57.6
890	536	0.40	442	4.9	506	339	238.0	45.2	622	20127	32.4
1190	560	0.44	846	4.3	805	649	378.4	45.2	1072	20307	18.9

20/40 Int. Density: 3.20 sp.gr., & L.T. - Kf = 25 Darcy's @ 3.0 lbs/sqft

300	480	0.42	100	7.6	199	77	133.5	42.0	252	21824	86.5
600	511	0.36	213	6.9	361	163	241.7	42.0	447	24168	54.1
890	536	0.40	442	6.2	635	339	425.7	45.2	810	24924	30.8
1190	560	0.44	846	5.3	1010	649	676.7	45.2	1370	25248	18.4

20/40 Sintered Bauxite: 3.58 sp.gr., & L.T - Kf = 40 Darcy's @ 3.0 lbs/sqft

300	480	0.42	100	8.5	223	77	205.1	42.0	324	27558	85.1
600	511	0.36	213	7.7	404	163	371.2	42.0	577	30882	53.6
890	536	0.40	442	6.9	711	339	653.9	45.2	1038	32128	31.0
1190	560	0.44	846	6.0	1130	649	1039.6	45.2	1733	32778	18.9

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) Cases

These 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.
FIG. 10 shows the first FFE scenario. It depicts the fracture half-width versus depth profile, and the penetration length distance (1190 feet) from the wellbore (denoted by the symbol Xf). Again, the Xf versus depth profile is artistic license, the computer generated fracture vertical height value is that shown where the fracture intersects the wellbore at Xf=0 feet, and the height remains constant to Xf=1190 feet. Also shown are the vertical extents of the pay, the vertical extent of the wellbore connection to the pay and the top of the proppant pack.
FIG. 11 shows the second FFE scenario with the proppant pile 100 FT above top of pay. The depiction is consistent with that shown in FIG. 10, with the top of the proppant pack at 100 feet above the top of the pay.
FIG. 12 shows the third FFE scenario with the proppant pile 200 FT above top of pay. The depiction is consistent with that shown in FIG. 10, with the top of the proppant pack at 200 feet above the top of the pay.
FIG. 13-A shows predictions for proppant quantity requirements for proppant packs that range from 25 feet below the top of the pay to 200 feet above the top of the pay. FIG. 13-B shows predictions for the change (delta) in proppant costs for proppant packs that range from 20 feet below the top of the pay to 180 feet above the top of the pay.
FIG. 14 shows the predictions for percent change from the base case scenario in production rate folds of increase (FOI) for proppant packs that range from 25 feet below the top of the pay to 300 feet above the top of the pay. Note that a proppant pile or bank extending 200 feet above the pay increases the production rate FOI by about 30 per cent. A proppant pile extending 50 ft (1.5 times the pay thickness) above the pay (100 ft) increases FOI about 10 per cent. Normally, an operator would seek an increase of at least 10 percent for the additional engineering and materials used for a fracturing treatment. Therefore, a lower limit for increasing the height of a proppant bank above the pay is preferably set at 1.5 times the pay thickness.
FIG. 15 shows the predictions for monetary net present return (NPVf) changes from the base case scenario for proppant packs that range from 25 feet below the top of the pay to 200 feet above the top of the pay. Under most favorably conditions, the present value of the well is increased by about $12 million, with a proppant pile above the pay a distance of twice the thickness of the pay. The slope of the curve is still upward at this distance.
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.