SECTION 1 MINIFRAC ANALYSIS
DESIGN
Over the past several years a considerable effort has been placed on improving the design and execution of hydraulic hydraulic fracturing fracturin g treatments, treat ments, It is evident that the mechanical mechanical properties of oil and gas reservoirs both from reservoir to reservoir and from well to well within the same reservoir. Recent improvements in well log analysis and three dimensional seismic seismic techniques have proven helpful in understanding reservoir reservoir properties. properties. Their applicability to hydraulic fracture design, howev however, er, are ar e limited. As a result, the use of minifracs minifrac s and microfracs have been developed to provide specific information, informati on, critical criti cal to hydraulic hydraulic fracture design. Since these procedures procedures involve involve the initiation of small fractures, the information can be applied directly directly to the design of larger hydraulic hydraulic fracturing fract uring treatments. This section has been devoted devoted to the use of minifrac minifrac tests in hydraulic fracture design. Both analysis techniques and minifrac design procedure procedures, s, to help get the best information possible possible from minifrac procedures, procedures, are ar e covered. The following glossary contains some some of the basic terminology terminology associated with hydraulic fracturi fr acturing ng and minifrac analysis: 1)
Breakdown Breakdown Pressure: Pressure: The pressure required to initiate init iate a fracture in a well for the first time.
2)
Bottom Hole Hole Treating Treat ing Pressure The pressure in the wellbore wellbore while conducting a hydraulic fracturing fract uring treatment on the adjacent reservoir. reservoir.
3)
Closure Closure Pressure: Equivalent to the least principal rock stress in the reservoir.
4)
Closure Closure Stress: The stress which is applied to the proppant bed after a hydraulic fracture has healed. Its value is equal equal to the instantaneous shut -in pressure minus the bottom hole flowing pressure. This value is time dependent.
5 )
Closure Time: The time measured from the point of of shut -in required for a created hydraulic fracture to close.
6)
Fluid Efficiencv: Efficiencv: The ratio of fluid volu volume me within the fracture at shut -in to the total fluid volume volume injected.
7)
Fracture Friction: The friction loss occurring occurring between between the casing and the fracture. Consists Consists of both perforation friction and flow restrictions restr ictions in the immediate wellbore wellbore region. Fracture Extension Pressure: Pressure: The lowest lowest pressure pressure at which fluid can be pumped pumped into a fracture and maintain propagation. Fracture
Pressure: Pressure: The pressure pressure required to open or dilate an existing exis ting fracture. fract ure.
10)
Fracture Gradient: A pressure over over depth ratio that tha t when multiplied by depth will yield the minimum pressure required to propagate a fracture.
11)
Instantaneous Shut -In Pressure (ISIP): The pressure observed immediately following shut -in after a hydraulic fracturing fract uring treatment. The difference between between this value and the fracture frac ture
2
extension pressure pressure is equivalent to perforation and fracture entry friction, combined with the in fracture friction fric tion losses from the wellbore to the fracture tip. 12)
Gross Fracture Height: The total height of the created fracture.
13)
Leak
14)
Matrix Flow: Flow: The flow of of fluids through a permeable permeable formation.
15)
Net Fracture Height: The portion of of the gross fracture height that covers a permeable zone where fluid loss can occur. Also referred to as the fluid flui d loss height.
16)
Net Pressure (delta Is equal to the bottom hole treating treati ng pressure minus the formation closure pressure. The net pressure is then the pressure responsible responsible for propagating the fracture and creatingwidth.
17)
Young's Modulus (E): The ratio of stress to strain str ain of a material undergoing elastic deformation. deformation. Also referred to as the modulus of elasticity.
The loss of fluid from a hydraulically hydraulically created fracture to the matrix of the reservoir.
MINIFRAC TESTING PROCEDURES There are basically basically three types of minifrac procedures: procedures: The step rate test, the pump -idflow-back test, and the pump -idshut-in test. There are, howeve however, r, several variations o off these three tests commonly commonly used used when conducting minifracs. Analysis Analysis techniques vary sigruficantly, sigruficantly, but but minifrac test procedures procedures almost always fall within one of of these three thre e general classifications. A minifrac treatment may involve one, two upon the required two or all three of these tests depending upon information. information. Minifrac tests should always always be designed specifically specifically to obtain the information required to design the main treatment for a particular well. Following is a brief description of the basic types of minifrac procedures and how they can be used to obtain desired information about the subject well.
Rate Test:
was developed as a means to determine the fracture extension pressure, which is The step rate test was i s the pressure pressure required to pump fluid into a propagating fracture. The injection rate at which this occurs can also be very interesting, but may may vary sigruficantly depending upon upon viscosity, viscosity, fluid loss properties, and a nd the production production history of the well. To perform a successful successful step rate test, injection must must be started at matrix rates and then increased in incremental steps until a fracture has been created and extended. extended. Rates should be held constant during dur ing each increment increment until conditions have have stabilized and maintained for approximately 2 minutes beyond this point. NOTE: Stable condition does does not necessarily mean mean constant consta nt pressures. pressu res. It may be be a situation of a constant rate of increase or decrease in pressure at a constant injection injection rate. A typical procedure for a step rate test in a low permeability well would be as follows:
Begin pumping at 0.1 0 .1 and maintain this rate until the t he pressure conditions stabilize. Pump for 2 additional minutes minutes at this rate. Then increase the rate in incremental steps to 0.2
3
0.4 0.3 0.5 1.2 and 0.7 0.9 1.5 letting the pressure conditions stabilize for 2 minutes before increasing to the next higher rate. The maximum pressure at each rate should be recorded and the bottom hole treating pressure at that point calculated.
Make a plot of bottom hole treating pressure versus injection rate. The fracture extension will appear as an inflection point on this curve since once the fracture has opened and width has developed, the pressure required to extend it will not change excessively with increasing injection rate. See figure 1. A modified step rate test has been proposed to obtain more information about naturally fractured high permeability wells. This procedure involves following a procedure similar to a standard step rate test except pumping is stopped after each portion of the test to record the ISIP and pressure decline. A complete analysis of this type of test has not yet been developed. There are, however, many observations that can be made using this test that cannot be made using standard step rate procedures.
i)
Friction losses during the the end of each pumping stage.
portion of the tests can be backed out using the ISIP at
ii)
The presence of natural fractures or high matrix permeability may be detected during the portion of the test by the presence of constant pressure increases during pumping. See figure 2. It may also be possible to detect multiple inflection points on the pressure versus rate plot, indicating the dilation of natural fractures creating excessive leak -off followed by fracture extension,
iii)
variations in the ISIP and the pressure decline may indicate the presence of a dual leak -off situation, caused by leak -off into natural fractures at higher net fracturing pressures. See figure 3.
iv)
Analysis of the pump in portion of each test can also be very helpful in evaluating the fracture opening pressure and confirming the fracture extension pressure and closure pressure.
NOTE: This concept of dual leak -off has been proposed by Warpinski A transformation was noted when injection rates were increased to a point where there was a significant increase in the net fracturing pressure. The resulting pressure declines showed three distinct fluid loss regimes. The first portion showed rapid leak -off, which tends to indicate leak -off in the presence of open or dilated natural fractures. The second regime shows sigtllficantly less leak -off from the main fracture after the closure of dilated natural fractures. The third regime occurs after closure of the main fracture and is essentially radial leak -off. Some of our own results indicate that the point at which this transformation occurs is very dependent upon both the injection rate and the treating fluid viscosity. Indications are that optimizing injection rate and fluid viscosity through the use of a modified step rate test may provide an effective means to reduce the leak -off into natural fractures. To date, results indicate that some wells will respond better to high rate, low viscosity treatments, while others will respond more favorably to
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viscosity treatments. The mechanism for this difference is not completely understood. Appendix A contains a report which gives a possible account for this behavior. TESTS The test is used to determine the closure pressure in low permeabilityformations. The test involves pumping a volume of fluid into the formation at fracturing rates, as soon as pumping stops the well is allowed to flow-back at a constant rate. The closure pressure is obtained from the inflection point on the pressure versus time plot as the flow-back changes from fracture flow to radial flow. There are several interpretations of closure on this plot. For the application of minifrac analysis the point of downward deviation should be viewed as the first indication of closure. This test is dependent upon the chosen flow-back rate. To get a well defined closure pressure it may be necessary to repeat this test several times using different flow -back rates. In some cases, plotting pressure against the square root of time may help an inflection point, if the flow-back rate chosen is too low to pick an accurate inflection on a linear scale. It is important to maintain a constant flow-back rate during a necessary to use a flowmeter in conjunction with an adjustable choke. (See figure 4.)
test. To do this it is
TESTS The pumpidshut - in test is a versatile minifrac test and, consequently, is probably the most common test used. This test involves pumping a volume of fluid into the formation at fracturing rates, stopping and monitoring the pressure decline. Although the basic procedure for this test is simple, there are a number of modifications that can be used to help define specific parameters. There are also many different techniques available to analyze the data recorded, and the many observations that can be made to provide some very useful information. Following is a summary of some of the information that can be obtained from using pump idshut -in tests: Fracture Gradient: The value obtained for the ISIP on a pumpidshut-in test can be used to obtain an accurate value for the static fracture gradient. This is equal to the pressure inside the created, open fracture immediately after pumping has stopped. This value for the fracture gradient will be dependent upon the volume of the injection test and the of fluid loss into the formation. It is very common to see increases in the ISIP when multiple injections are performed on a well.
Friction Pressure: A good estimation of the friction pressure during the pumpin portion can be obtained by the pressure during pumping and the ISIP. It should be noted that this number will consist of both pipe friction and fracture entry friction. Abnormally high values would be an indication of high fracture entry friction.
Closure Pressure:
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Often the fluid leak -off rate will be high enough that the fracture will close in a relatively short time after test. If this is the case, a pumpidshut -in test can be used to determine closure pressure, thereby, a eliminating the need to conduct a test. To determine closure pressure using a pumpidshut - in test, the pressure decline is usually plotted against the square root of time. Closure pressure is indicated when the pressure decline deviates from a straight line on this plot. There are other techniques available to help the point of closure. However, when it can be used, the square root time method has proven to be most reliable. Over laying a plot of the first and second derivative of the pressure decline on the square root time plot will help to identify possible straight line portions and inflections on the curve. Plotting the pressure against other functions such as the G function and the fourth root of time may be helpful in some cases.
Fluid Leak-Off Parameters and Fracture Geometry The analysis of pumpidshut - in tests makes it possible to obtain estimates of fracture geometry and fluid loss properties under actual insitu-conditions. This can provide more accurate data to use in design programs and help to optimize the subsequent fracture stimulation. When using results it is important to know that the analysis incorporates several assumptions may produce unrealistic results. For this reason, it is important to know the assumptions that are made and how they may have an effect on the final results. In some special cases it may be necessary to use questionable results, simply because more reliable information is not available with current technology. The following assumptions are commonly mad during minifrac analysis. These assumptions may or may not hold true depending upon specific conditions. All fluid loss is in the form of matrix leak -off into the formation which can be defined with a mathematical model. ii)
Fluid leak -off only occurs along the net fracture height interval.
iii)
The created fracture follows a symmetrical two wing fracture geometry which can be modelled using fracture simulation models.
iv)
Fluid degradation due to time and temperature are neglected in most cases.
v)
Fluid compressibility and expansion effects due to temperature require special consideration in a minifrac analysis. (See Appendix B.)
vi)
The created fracture closes freely without any interference.
vii)
In some models the fluid viscosity is not considered in the calculation of the fracture geometry.
Minifrac analysis is complicated by the fact that there are several different analysis methods available to the industry. Choosing the proper minifrac analysis for a particular well can be a difficult problem if one does not have a good understanding of the different methods that can be used. There are also several additional factors that must be taken into account regardless of which minifrac analysis method is used.
Following is a quick overview of some of the most common analysis methods currently being used. Method
Program out dated)
This method utilizes two material balance equations during pumping and after shut -in, and employs a curve matching technique to determine a match pressure which is then used to calculate the following fracture parameters: fracture length, width, fluid loss coefficient, closure time, and fluid efficiency. At its conception, type curves had only been developed for the PK geometry model, it has since been expanded to include type curves for CZ, Vertical Penny, Horizontal Penny, and Ellipsoidal geometry models. A major drawback with this analysis is that it assumes that the created fracture width is proportional to the pressure difference between the ISIP and the closure pressure. If this difference is quite large (greater than 1.5 the calculated widths can be several times greater than those predicted by a fracture design program employing the same geometry model. This result will also tend to predict excessively long closure times when compared to the actual observed closure. When differences such as these are noted, the usefulness of the results from the minifrac analysis are very questionable.
Fluid viscosity is not considered in the geometry calculations predicted by this method. Method
out dated)
-
This method uses the measured closure time to analytically determine the fluid efficiency. Once the fluid efficiency has been determined, the geometry calculations can be completed using techniques similar to those used in Method # 1. This method can be used to calculate the same parameters using the same geometry models as Method Fluid viscosity is not considered in the geometry calculations predicted by this method. Method
(EFP)
This method is based on an energy balance equation used in conjunction with fluid rheological properties to predict more realistic fracture geometries. The assumption of fracture width being proportional to the difference between the ISIP and closure is not made in this analysis. Since the rheological properties of the fluid are important in this analysis, good quality control practices during the minifrac test are required to provide the necessary information to conduct the analysis. The energy balance method offers two procedures that can be used to conduct the analysis. The first procedure involves using field measured closure pressure and closure time, while the second uses pressure decline data to match type curves and determine P*. The type curve approach calculates a closure time. If this calculated value differs considerably from the observed closure time, the reliability of this analysis will be in doubt. The method using observed closure pressure and time should be used unless these values cannot be accurately determined. The type curve procedure provides a method that should be used in cases where closure be accurately determined.
This analysis can also be used to calculate fracture parameters following a treatment which uses proppant. In this case, only the method using field observed closure should be used. One reason for this is that the presence of proppant in the fracture can distort the pressure decline making meaningful curve matching impossible. In a situation where an analysis is being conducted after a main treatment, it is necessary to monitor the decline until after closure has been detected, as the closure pressure after the main treatment will almost always be higher than the value determined prior to the treatment. The energy balance method will predict the fluid loss coefficient, fluid efficiency, closure time (when applicable), created fracture length, and created fracture width. The geometry models currently available for this analysis are: PK, CZ, Horizontal Penny, Vertical Penny and Ellipsoidal. Another option is available for both the PK and CZ geometries to provide quick and accurate analysis. This procedure is outlined in Appendix C. Method
3 D modelling and matching
As the fracturing models have continued to improve with the development of better and faster computers, other more reliable methods have been developed to analyize minifiac data. In many cases it would be preffered to use the same model to analyize the minifiac data and to design the fracture treatment. One means of doing this would be as follows: 1)
Conduct pump -idshut-in test at design rates using the same fluid to be used for the fracture treatment and monitor pressure decline until after closure has been detected.
2 )
Using dimensionless closure time go to figure and determine the fluid efficiency. This can also be done using the EFP program or similar analysis to determine the fluid efficiency based upon the closure time.
3)
Go to the desired design program (XTENT or Prop)and guess at a value for the fluid loss coefficient (Cw). Compare the calculated fluid efficiency and closure time to the actual fluid efficiency and closure time.
using
4) 5 )
values for Cw until the fluid efficiency and closure time have been matched.
If a 3-D model is being used, it is also possible to adjust the stresses and rock properties to match actual conditions. In doing this it is also possible to match the injection pressures as well as the pressure decline. When ever possible, it is recommended to complete a complete match such as this in order to simulate actual conditions as close as possible.
This procedure makes it possible to conduct a 3-D minifrac analysis by using a 3-D model in the interative process. It must be noted that good stress data is necessary to obtain good information these models. It is also desirable to pump larger fluid volumes in this type of analysis to help establish good and realistic results. A good size for consideration would be a volume equivalent to the pad volume of the proposed treatment. Many newer design models have been created to this procedure or one very similar to be used for minifrac analysis. In many cased, the interative procedure may not be required.
MODEL CHOICE This section will consist of a brief description of the geometry models that are available and ideas on when they should or should not be use.
a
1.
Perkins and Kern The PK model is one of the two most common models used in two dimensional fracture design programs. This geometry predicts no slippage along the bedding planes yielding an oval type height profile with width and volume equations as shown in Figure 6 . When using conventional minifrac techniques described in Methods 1 and 2, the PK geometry will tend to predict very long, narrow fractures that result in extremely low values for the fluid loss coefficient. This is especially true in cases w ere the gross fracture height is small since the fracture 4 volume term for this model is a function of H L gross fracture height, L fracture length). The model tends to make more realistic predictions for larger gross heights of 30 m or greater. For fracture heights of less than 30 m, the results tend to be quite unrealistic since a small error in the gross height will have effects on the final outcome of the analysis. =
=
The energy balance method will produce realistic results over a wide range of fracture heights. It is very important to input the correct gross height for the program to make meaningful predictions since it is a two dimensional model. 2.
Christianovitch and Zheltov The CZ model is the other most common model used in two dimensional fracture design programs. This geometry assumes that there is slippage along the bedding plane and predicts a more rectangular width profile with width and volume equations as shown in figure 7. Conventional minifrac analysis explained in Methods 1 and 2 predict geometries which are short with large fracture widths. The fracture volume term for model is a function of 2 and is less sensitive to any errors in the estimation of gross fracture height than the PK model (H gross fracture height, L fracture Length). Because the model tends to predict shorter and wider fractures, the values for the fluid loss coefficient are often very high. Comparison of observed to actual closure times can provide an indication of how good the predictions are. differences between calculated and observed closure times are an indication that the predictions are not a good representation of actual conditions. =
=
The energy balance method will make more consistent predictions of fracture geometry than conventional methods when using the CZ geometry. Meaningful results are dependent upon inputting the correct gross fracture height as in any two dimensional model. 3.
Horizontal Penny The horizontal geometry has a circular profile of height and length. It is assumed that the fracture cannot propagate out of zone (the diameter will not exceed the net pay). As a result of this, the entire fracture face is considered to be leak -off area which will tend to produce a low fluid loss coefficient. The horizontal penny model should be used in cases where a horizontal fracture is anticipated or in a massive formation with only a small perforated interval.
4.
Vertical Penny The vertical penny geometry has a circular profile of length and height similar to the horizontal geometry. The major difference is that the diameter may exceed the net pay. The leak -off is restricted to the net pay height and not the entire fracture face, occurring in wells with a relatively small net height interval and a very large gross height.
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5.
The ellipsoidal geometry was developed specifically for use in massive formations with large perforated intervals. In this case the height, due to the large perforated interval, may exceed the created length.
6.
3-D. 3-D More and more 3-D type programs are becoming available for fracture treatment design. When ever it is possible it would be strongly recommended to use one of these models for the fracture design and minifrac modeling. Even in cases where stresses are not known, it is probably more reasonable to estimate stresses than it is to estimate the fracture height as in most 2D models.
CHOOSING THE CORRECT
TECHNIQUE
The industry has not developed minifiac analysis techniques to the point where there is a right and a way to conduct the analysis. There are, however, several pointers that can be used to establish the best method for a particular application. Some of these pointers are described below: A) Closure Time (Measured vs Calculated)
Most minifrac analysis programs that use a curve matching technique calculate a closure time based on the predicted parameters. Should the calculated closure time vary significantly from the measured closure time, it is an indication that the analysis results are unreliable. When this is detected it would be preferable to use a technique which bases its calculations on measured closure pressure and time. This demonstrates the importance of monitoring the pressure decline until after closure has been established. It is important to obtain an accurate value for closure pressure and closure time. B) Geometrv Predictions
In order to provide good results, the fracture parameters determined from the minifrac analysis must be consistent with the parameters predicted by the design program. The fluid loss coefficient predicted by the minifrac analysis is dependent upon the area of the fiacture face created in the minifrac test. If the fracture geometries used for the minifrac analysis and the design programs are inconsistent, the fluid loss coefficient predicted by the minifrac analysis will not be a reliable value for use in the particular design program. When such inconsistenciesare detected either a different minifrac model or a design model should be considered. To avoid these inconsistencies, it is strongly recommended to use the same model to complete the minifrac analysis and then the treatment design.
Size of Minifrac Test When using a 2-D model to design and analyze a minifrac, it is important that the tests be large enough to establish fracture height to the predicted barriers. A rule of thumb when designing minifrac tests is that the length must be at least three times the gross fracture height, if the created fracture height is to have any change of reaching the predicted
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If a 3-D model is being used to design the and the job, several simulations can be completed to determine an optimum volume which will establish sufficient geometry to be representative for the main treatment. Whenever possible it is recommended practice to a measured value of the gross fracture height by injecting radioactive isotopes and logging immediately after the test using a spectral gamma ray tool as well as a temperature log. It is important to have a very good value for the gross fracture height in order to obtain the most representative minifrac analysis possible and to confirm the geometry predictions by 3D models.
MINIFRAC DESIGN AND APPLICATION The most important thing to remember about design is that minifracs should be designed on an well basis to obtain the specific information required to complete the design on that well. Due to highly variable well conditions, there really is no standard procedure that can be used for all cases. Formation closure pressure is a very important parameter that is used extensively in both minifrac analysis and real time treating pressure analysis. It is, therefore, very important to a good value for the closure pressure. In most cases a pumpidshut - in test can be used to determine closure pressure. In some cases, however, it may be necessary to use a pumpidflow-back test particularly in low permeability reservoirs. Fluid choices are dependent upon the information desired from a particular test. For example, if a pump test is being conducted strictly for the determination of closure pressure, a lower viscosity, high leak -off fluid should be considered to promote more rapid closure and give a more pronounced inflection indicating closure on the pressure decline curve. When determining fluid loss parameters, however, the fluid used should be same fluid proposed for the main treatment to provide meaningful design parameters to put into the design program. Following is a summary of design parameters that should be considered when designing minifrac tests for any particular well. The parameters are dependent upon the desired information and will also be influenced by restrictions due to well configuration, pressure limitations, etc. DESIGN CONSIDERATIONS FOR MINIFRAC TESTS A.
Considerationsfor Desired Information
1. Step Rate Test
Determine Fracture extension Use a friction reduced fluid. Begin test pumping below fracturing rates and pressures. Incrementally increase the rate maintaining each rate long enough to let conditions stabilize (3 to 10 min.).
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an inflection pi n t on a pressure versus injection rate plot where the maximum pressure p i n t at each increment is plotted against its corresponding rate.
- Extension pressure is found by
- The choice of injection rates can be optimized somewhat by the use of
law as follows:
=
7.08 K H
Where: Q
flow rate K H height (ft) P pressure (psi) viscosity r radius from wellbore
=
=
=
=
=
=
Detection of leak -off Consider a modified procedure into natural fractures, incorporating a shutdown and (complex conditions) ISIP after each rate increment. - Higher viscosity fluids may be looked at if
excessive leak -off restricts fracture propagation.
- Plot the maximum pressure and the ISIP at each increment against the rate.
- As rates are increased, look for the appearance of a dual leak -off system (multiple closures indicated on pressure decline). This may be accompanied with an increase in net treating pressures.
2. Pump-mo w-Back Test
Desired Information
Desien Considerations
Determine formation Closure pressure - Use a friction reduced fluid, base gel.
Pump a volume of fluid at fracturing rates. as pumping has stopped begin flowing the well back at a constant rate using an adjustable choke As and flowmeter to maintain constant rate. - Monitor pressure until after the fracture has closed.
Shut-in and monitor pressure recovery until it stabilizes. Plot the pressure decline versus time and square root
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time. If it is difficult to detect closure, consider conducting additional tests using flow -back rates.
3. Pump-Idshut-In Tests
Fracture gradient. Pump at fracturing rates and pressures. -
Shut down and record ISIP. gradient
=
ISIP + Depth
Pressure
Pipe friction pressure and fracture entry Use pad fluid.
- Inject at fracturing rates and pressures and allow conditions to stabilize. Shut down and record ISIP. - The combination of pipe
friction and fracture entry friction is the difference between the pressure while
pumping and the ISIP. Closure pressure. Use pad fluid or base gel. - Inject at fracturing pressures and rates until
conditions stabilize.
Shut down and record pressure decline. Plot pressure decline against the square root of time and the the first and second derivative to determine straight line protions and points of inflection. In some cases other functions may be plotted to help determine closure. Most commonly the functions used will be either square root of time or G function. Fluid loss parameters. Use pad fluid proposed for the main treatment. If possible conduct at design rates. -
constant rates while pumping.
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If using a 2-D model, use the EFP program with estimated Cw to design treatment so that the length (one wing) is at least three times the gross fracture height. make the treatment large enough to reach the upper and lower barriers.) If using a 3-D model the minifrac test should be modelled ahead of time to ensure that the injected volume is adequate to create the desired geometry.
Spurt losses: Spurt losses are ignored in most common types of minifrac analysis. In some areas particularly in high perm or over stressed, depleted reservoirs, the spurt losses can be very and result in very miss leading results from standard minifrac analysis. The main reason for this is that the effective fluid loss determined by minifrac analysis assumes a zero spurt. Depending upon the spurt time and volumes, this number will be very dependent upon the volume pumped and the pumping time. In cases where spurt times are high (over stressed reservoirs) the Ceff can vary with volume. Typically if a smaller volume is used an artificially high fluid loss coefficientwill be calculated meaning more pad would be used than actually needed.
If there is an indication that spurt losses are very high, then there are 2 alternatives for minifrac anaylsis that could be used which are described as follows: 1.
2.
Shadow frac: A shadow frac is basically a minifrac where the treatment volume is very near the total planned volume for the entire job for the well. By conducting a shadow frac, a single point is defined for the effective fluid loss coefficient which assumes spurt losses to be zero. As long as the volume of the main treatment is close to the same size of the shadow frac, this value will be suitable for the design. This option is very expensive for large jobs and as a result would have a very limited scope of use. Dual Leak off Testing: Here a series of 2 minifrac tests are completed on the well using the following procedure. The first minifrac is pumped using the proposed fracturing fluid at design rates. The volume of this test should be relatively large and should not be less than the planned pad volume. Following the first minifrac injection, monitor the pressure decline until after formation closure has been confirmed. Conduct a quick analysis to determine the fluid efficiency and the volume of the fracture at the end of pumping. Pump a second minifrac test using the same fluid and injection rates as for the first test. The total volume of this test should be not greater than the fracture volume determined from test 1. Since the entire fracture face exposed to the second test has been previously covered during the first minifrac test it can be assumed that the spurt loss is equal to zero for the second test. A standard minifrac analysis can than be completed to determine the effective fluid loss
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Once the fluid loss has been determined for the second test, it is possible to use this value with the data from the first minifrac and iterate to determine a value for the spurt losses. This analysis can also be completed using the EFPS model, but in this case would be restricted to a 2-D model. Using the iterative technique it is possible to complete the analysis with a 3-D model.
B. Design Considerations for Suecific Well Conditions
Specific well conditions should be considered when designing tests in order to obtain the maximum benefit from the tests. Following is a summary of specific well conditions and the corresponding design considerations. 1. Poor Fracture
Containment:
In the case of poor fracture height containment, there are 2 basic design approaches that should be considered. The first approach is to look at the interval and determine if there are barriers farther up and down the hole. If there are, then it may be possible to conduct a very high rate treatment with a more conventional design. If the zone is very large and there are no likely barriers at all to control the height, then a moderate rate tip screen out design should be considered. This design considers the probability that there are slight stress variations throughout the zone and the width profile can be complex which will typically result in a reduced over all with. By pumping lower proppant concentrations until a tip screen out has started, proppant is transported more effectively throughout the fracture. By continuing to pump after the initiation of the screen out, the net pressure increases will create width and allow additional proppant to be placed. To design this type of job, a model that will allow pumping to continue past the tip screen out condition should be used such as the Fracpac model. Some possible minifrac considerations for this type of response would be as follows: Conduct modified step rate test consisting of a series of pumpidshut - in tests increasing rates from one test to the next. -
Pump a minifrac of large enough volume to view a plot to see the severity of the pressure response. Determine closure pressure, closure time and Cw by conducting a complete analysis. - Record
and pressure declines (a decrease in ISIP is an indication of propagation into a zone of
lower stress). Conduct temperature and radioactive surveys to establish height. A 3-D fracture design model should be used for this type of well so that the design can be verified by comparing to observed results. 2.
Fracture Gradient:
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High fracture gradients are a direct result of high formation stresses. In some areas the presence of high formation stresses can be coupled with relatively low pressure which will often result in very high fluid loss. Another possible problem associated with high stresses is that complex tectonics may be the cause of high stresses. In this case stress orientation may be complex resulting in complex fracture geometries. In areas where high stresses are encountered minifrac tests should be considered to evaluate the following items. Accurately determine closure and evaluate net fracturing pressures. High net fracturing pressures are a strong indication of complex geometry and special design considerations may apply. Check for abnormally high fluid loss. Check for high fracture entry friction. Check for dual leak -off behavior often accompanied by rate test) -
high net fracturing pressures. (modified step
3. Presence of Natural Fractures:
If natural fractures are anticipated in a well that is to be fracture stimulated, there are a number of items that must be considered before completing the design. Perhaps the biggest problem with naturally fractured reservoirs is that conditions often vary significantly from well to well making a simple design quite It is for this reason that it is recommendedthat a minifrac test be completed prior to each design in such reservoirs. The minifrac should be used to determine the effect that the natural fractures are having on the hydraulic fracture treatment. In some cases there may only be minimal effects as a result of the natural fractures, but in other cases, high treating pressures, complex geometries and excessive fluid loss are also possibilities. The minifrac will make it possible to evaluate the well prior to the frac treatment so that the design can be tailored to meet the conditions specific to that well. Following are some points that should be considered when designing and analyzing the minifrac.
- Consider a modified step rate procedure to help establish if natural fractures are a possible source of
high fluid loss. Check for the presence of dual leak -off or multiple closures indicating leak -off into natural fractures. the static fracture gradient, fracture extension pressure and closure pressure. If possible, pump long enough to view a plot of net fracturing pressures versus time. A complete minifrac anaylsis should be completed to evaluate closure pressure, closure time, the fluid efficiency and the fluid loss coefficient.
If it is determined that the natural fractures are a very significant source of fluid loss, it may be desirable to look at changing the fliud system. In extreme leak off cases, some very significant improvements have been noted by using a more viscous fluid.
16
4.
Leak-Off: High leak -off only poses a serious concern when you are not prepared to handle it. In wells where high leak off is a concern, special consideration should be to designing a screen out design. The purpose of this is to first optimize the use of fluid and second to create a with maximum conductivity. In a high perm, high leak off well the minifrac must have large enough volume to out weigh the effects of spurt losses. If large spurt losses are expected, it should be recommended to conduct a series of 2 minifrac tests. The first test is of large volume and is fully exposed to the spurt loses while the second test should be kept smaller so that it stays within the first fracture where the spurt volume has already been completely filled. The second test can be analyzed assumming zero spurt to determine the fluid loss coefficient. This can then be used with the decline from the first test to determine a value for the spurt losses. increases in the ISIP from one test to the next is an indication of high leak -off causing pressurization of the near wellbore region. This should be expected in low permeability formations or depleted wells. The final design should be based upon the fluid efficiency, closure time, closure pressure and fluid loss as determined from the minifrac. Large pad volumes will usually be required in cased where fluid loss is very high. Examine the possibility of treating at higher rates to help offset the high rate of fluid leak -off.
5. Low Leak-Off:
If closure cannot be easily defined, consider the use
of pump -idflow-back test to help
closure.
-
Check fracture entry friction to ensure that there are no restrictions near the wellbore causing this response. Fracture height containment may be a concern in very low leak -off wells due to high fluid efficiencies. It may be desirable to consider a lower rate treatment or the use of a lower viscosity fluid for the Pad. Net pressures during pumping can be used as a possible guideline for height containment. Typically higher net pressures are an indication of better fracture height containment where low net pressures are an indication of very poor fracture height containment. Anytime proppant is pumped into a low permeability well, inducing closure should be advised to minimize proppant settling.
-
6. High Net Fracturing pressures - When high net fracturing pressures are detected, it
may be an indication of high perforation friction or high fracture entry friction which is commonly reffered to as fracture tortuosity. The primary objective here is to if it is perfortation friction which could be corrected by an acid treatment or reperforating or if it is a fracture entry problem which may require some special design considerations. The best means to conclude if the high net pressures are caused by perforation friction or tortuosity is to inject the same fluid into the formation at 3 or 4 injection rates. Make a plot of net pressure vs injection rate and if the problem is perforation related the net pressure will increase significantly with
17
injection rate with the curve accelerating as injection is increased. If it is a tortuosity problem the net pressure increases will tend to level out as the injection rate is increased resulting in a flatter curve. It must be noted that in some cases complex fracture geometry can cause similar high net pressures but may be inconclusive when plotted as above. Some knowledge of the region can be very helpful if complex conditions are expected. Some design ideas to help deal with this situation are described in the Real Time Analysis section of this report.
18
SECTION 2 - TREATINGPRESSURE ANALYSIS
Treating pressure analysis involves interpreting pressures during pumping to determine how a hydraulic fracture is progressing during the treatment. There are many factors that may have an effect on the fracturing pressures during a treatment. These factors include fracture propagation properties and geometry, as well as treating rates, fluid viscosity, fluid leak -off, proppant concentration, and formation properties. A common mistake made by many people is to restrict treating pressure analysis entirely to the interpretation of a net fracturing pressure delta P) plot.
In fact, there is a tremendous amount of information that can be obtained from plots of treating pressure, injection rate, proppant concentration, viscosity, and in the case of crosslinked gels, the liquid additive rate. For example, changes in pressure may result from changes in friction pressure due to variations in base gel viscosity, or improper crosslinker addition, changes in treating rate, or variations in proppant concentration entering the fracture. Pressure responses caused by any of the above factors may cause fluctuations on the delta P plot that can be misinterpreted very easily when treating pressure analysis is not coupled with a complete analysis of treatment data. Since meaningful interpretation of the delta P plot is dependent upon several treatment variables, treatment execution and quality control play a very important role in treating pressure analysis. The major goal in treatment execution when pressure analysis is being conducted, is to minimize the number of variables in a treatment by keeping treating rate, base gel viscosity, and additive additions constant during the treatment. Changes in proppant concentration should be smooth to reduce the possibility of pressure fluctuations caused by sudden variations in proppant concentration. Maintaining these values as constant as possible effectively reduces a number of variables, and makes it feasible to conduct a more complete analysis of treating pressures and fracture response. - NET PRESSURE PLOT
INTERPRETATION
The use of the plot of net fracturi g pressure versus time to analyze treating pressure response 18 was initially developed by NOLTE AND SMITH . A mathematical solution was developed to predict how the treating pressure should respond for the ideal situation of a hydraulic fracture propagating with constant height and no fluid loss. To complete this solution, the following assumptions were made: i) The fracture exhibits a Perkins and Kern fracture geometry. (Negligible slip of the bedding planes). ii) The fracture has constant height. iii) The fracture consists of two symmetrical wings. iv) Injection of a Power-Low fluid at a constant rate. By comparing the predictions of the mathematical solution to the pressure responses from several fracturing treatments, an idealized delta P plot was developed. This idealized plot consists of different pressure responses that are commonly seen during fracturing treatments. These responses were then explained either by the way they related to the predicted response or by considering specific assumptions that may not hold true in a particular situation resulting in deviations from the predicted response. As a result, each portion of this plot can be interpreted as a pressure response caused by the progression of the propagating hydraulic fracture.
19
Figure 1 shows an idealized delta P plot which follows a logical progression of a fracture treatment. Many fracturing treatments will follow a progression very similar to this idealized plot. There are, however, several cases which may follow a different progression. For these cases, the plot may be broken down but the same basic rules regarding breakdown and analysis of the plot will still apply. Nearly all treatments can be broken down into several portions which can be described or explained as follows: a.
1,
1
0.33, which corresponds very This response is characterized by a positive slope typically between closely to the mathematical predictions for the idealized case proposed by Nolte . As a result, this response can be interpreted as propagation with unrestricted length extension and little or no vertical height growth.
In general this condition is favorable since the fracture is propagating according to design assumptions. This will result in efficient use of the fracturing fluid, combined with effective proppant placement over the zone of interest, which should provide good post treatment results. Despite the fact that a slight positive probably very dependent upon fluid loss. Nierode throughout a treatment as a function of fluid loss.
for the ideal case, the magnitude of this slope is had found that net fracturing pressures tend to increase
Fracturing fluid invading the formation will tend to increase pore pressure and, consequently, increase the stress level required to hold open the fracture. In many cases this pressure will increase throughout a treatment until a critical pressure is reached. At this point the net fracturing pressure exceeds the strength of the barrier rock, possibly causing the fiacture to propagate out of zone.
Higher leak -off will tend to result in a greater positive slope on the delta P plot. Since this may reduce the available pumping time, smaller volume, higher rate treatments may be more successful in wells that exhibit more rapid pressure growth. Lower leak -off will result in a smaller positive slope on the delta P plot. In this response, very large treatments can be placed with efficient use of fracturing fluids and effective proppant placement. b. Figure 1,
This response is characterized by a near zero slope on the delta P plot which may be very slightly positive or very slightly negative in any particular case. This response had initially produced a great deal of confusion due to contradicting data that was seen when evaluating the results of several wells. Using an idealized mathematical solution for the geometry, Nolte speculated that this response could only be the result of accelerated height growth or accelerated fluid loss, possibly into natural fractures. In cases this appears to hold true, but in too many cases wells exhibited this response throughout still allowing large quantities of proppant to be placed at high concentrations on a routine basis. speculation of accelerated height growth accelerated fluid loss did not seem to hold true under
20
Work done by Conway indicated that Nolte's assumption that the propagating fiacture following a Perkins and Kern geometry does not hold true in all cases. Solving for a Christianovitch and Zheltov model resulted in an ideal case where a near zero slope or even sightly negative slope was predicted. A second interpretation of this response could then be made assuming a Christianovitch and Zheltov fracture geometry. In this case this response would be interpreted as nearly perfect height containment combined the good fracture width development. In such a situation very large treatments can be placed making very efficient use of fracturing fluid and effective proppant placement usually providing excellent post treatment results. Nierode
explains the differences between the Perkins and geometry and the Christianovitch and geometry very well. The major difference resulting in the noted pressure responses is that extremely good width development in the C -Z model results in reduced in -fracture friction pressure losses, which produces the slightly decreasing pressures as the fracture becomes longer and wider. The P-K model, however, predicts in fracture friction pressure due to less width development than the C -Z model. As a result, the P-K model predicts increasing pressures as the fracture grows in length. The problem then becomes determining which model best fits a particular well. The most effective means of doing this is through knowledge of the area from previous jobs done. Unfortunately, in many cases this information is not available, making it necessary to use other information to help make the decision. Following are some rules of thumb that can be very helpful in determining the model which best suits the response of a particular well. i)
The K-Z model assumes slippage along the bedding plane. As a result, this response would be more likely to occur in shallower formations with very good barriers and relatively low stresses.
ii)
The C-Z response is indicative of almost perfect fiacture height containment. As a result, wells exhibiting this response should only fail in a tip screen-out mode they will not fail as a result of excessive height growth).
iii)
A well which follows the P-K model will tend to be difficult to following information can be used to help this response in
Some of the cases.
treatment begins with a positive slope similar to that described in Figure 1, Region I prior to exhibiting the zero slope response in Region 11. the treatment begins to go into a sharp negative slope indicating the initiation of the treatment screens-out very prematurely indicating excessive fluid iv)
c.
excessive height
loss.
Minifrac analysis can be very helpful in making a decision regarding the best model to describe the response. Treating pressure response during the pump-in portion of a test combined with the pressure decline can be very helpful in high leak -off and possibly height growth.
1
This region is characterized by accelerated pressure growth while pumping at constant rate. On the delta P plot this will appear as a positive slope of 1: 1 or greater. When this response occurs it is an indication that fracture growth has essentially stopped due to a screen-out at some point within the fracture. Additional fluid injected into the fracture will tend to balloon the existing fracture (creating a storage with
21
no additional fracture extension. The slope of this response is proportional to the percentage of the existing fracture which is acting as the storage volume. This has been summarized in the following table.
SLOPE OF
CURVE
1:1 2: 1 3: 1 4:1 5: 1
PERCENT OF CREATED FRACTURE ACTING AS STORAGE VOLUME Screen-out) 100% 5 0% 33%
25% 20%
Since this response indicates that fracture growth has stopped, it will usually be followed by treatment termination due to an incomplete screen-out. The time from where this response is initiated and treatment termination is dependent upon the length of the created fracture. In a small treatment with a short fracture length, termination can occur very fast due to the small storage volume available. In a large treatment, however, the long length can provide substantial storage volume, making it possible to pump for a considerable time before treatment termination, due to a complete screen-out, is reached. As a result of this, it can be very difficult to determine the proper time to end the treatment so as to not leave an excessive amount of proppant in the tubulars after a screenout has been reached. In general, small treatments will screen-out very fast making it desirable to end the treatment after a 1: 1 slope has been initiated. Larger are much more difficult to call. Experience in an area may be the best determiningfactor.
If there is any doubt on when to end a treatment, the treatment should probably be continued until screen out, to maximize the proppant placed into the fracture. d. Figure 1
This region is characterized by decreasing pressures at constant injection rates caused by the fracture propagating out of the primary zone into a zone of lower stress. When this occurs the fracture will preferentially propagate into the lower stress zone, resulting in excessive loss of pad volume and, consequently, the reduction of fracture width in the primary zone. As a result, this response will usually be followed by a very rapid screen-out mode after the pad has been depleted. Since the idealized delta P plot proposed by Nolte does not cover all cases, Conway etal 17 developed a set of type curves which can be used to pressure responses. These type curves have proven to be particularly useful in post treatment analysis, making it possible to a well by its response and adjust subsequent treatments performed in the area to improve the design based on pressure behavior typical to a given area. Since in many areas adjacent wells respond very similarly, this procedure has helped to vastly improve the results of fracture stimulations. The five type curves proposed by Conway a) Christianovich b) Perkins and Kern d) Medlin e) Nolte
to describe formation response are:
22
a) Christianovich This type of well exhibits nearly constant BHTP plus or minus a slope of 0.05 on the P plot until a tip screen-out mode is reached as shown in Figure 2.
delta
This response follows very closely the mathematical predictions made using the Christianovitch Zheltov fracture geometry. Post treatment analysis has also demonstrated that the created fracture length can be predicted with very good accuracy using the Christianovitch (Daneshy width equation. For this case it appears that fracture height has been perfectly contained within the barriers. This coupled with excellent fracture width development makes it possible to place high proppant concentrations effectively over the zone of interest. This accounts for the fact that these wells will usually show excellent post treatment results. b) Perkins and Kern
As the name indicates, this type of well will respond very similar to the mathematical predictions made using the and Kern fracture geometry. As a result, the idealized delta P plot proposed Nolte will provide an excellent representation of this response. Since this has already been covered in detail in the previous section, it will not be considered further at this point. Two possible type curves for this response are shown in Figure 3.
c) Penny A Penny type response will usually occur when there are no barriers available to restrict vertical height growth. Under these conditions the fracture may exhibit height growth equal to or greater than fracture length growth, resulting in a circular or elliptical profile. Due to the fact that these grow in height as fast as they grow in length, it is very to establish fracture width. As a result, the placement of large proppant volumes is very and i n particular, placement of high proppant concentrations is almost impossible. Another concern is that if stresses vary slightly within the zone, the resulting width profile will tend to be slightly complex and the overall width will be further reduced. A typical delta P plot for this type of well is shown in Figure 4. Because of the excessive height growth, the bottom hole treating pressure will decline steadily until a screen-out mode is reached. Due to narrow fracture width, these wells will usually screen-out very quickly once a screen-out mode has initiated. At this point, the proppant concentration exceeds the fracture widths capability for accepting proppant, leaving very little area available for storage volume. This usually results in a very rapid screen-out likely initiating at a slope in excess of 2: 1 on the plot.
d) Medlin
The Medlin type response is identified by large pressure increases during pumping. These pressure increases can be continuous through ut the treatment or there may be several unpredictable pressure fluctuations. Medlin found that flui d viscosity can determine if the
23
pressure follows a smooth increasing trend or an irregular increasing trend with several fluctuations. Figure 5 shows an example of a delta P plot that would be expected for a Medlin type well. In many cases a screen-out mode may be initiated as soon as viscous fluid reaches the formation. This response most often occurs in formations that are highly jointed or faulted. It appears that in areas where the second principle stress is moderately greater than the least principle stress, the growth of the induced fracture can be restricted by these jointed patterns. This may be caused by the interference of natural fractures and stress variations at the induced fracture tip or by excessive leak -off into the jointed pattern resulting in the development of a complex fracture network. This concept seems to be supported by post treatment analysis which consistently shows much shorter than expected fractures in these wells. Since hydraulic fracturing in heterogeneous or naturally fractured reservoirs is at best recommendations must be made on a well to well basis. To do this effectively, tests should be conducted prior to conducting any treatment in an area where this response may be expected. e) 14 It is important to note that this response is in no way related to the work done by Nolte covered earlier. This response is characterized by above normal fracture gradients, high net fracturing pressures, near constant bottom hole treating pressures during pad, followed by the initiation of a screen-out mode when proppant reaches the formation. An example of a delta P plot for this type of well is shown in Figure 6 . This response usually occurs in highly stressed, highly naturally fractured formations. One possible explanation of this response is a complex system of fractures in the near wellbore region perhaps resulting in two or more fractures propagating parallel to each other. In such a case fracture width development is restricted, resulting in the rapid screen-out mode. As a result, deep proppant penetration away from the wellbore is difficult to obtain and the results of fracture stimulations in these wells tend to be very disappointing.
type well, but There are some techniques which may improve stimulation results in a Nolte these recommendations will depend upon specific well conditions and should only be made on a well to well basis. Minifracs should be recommended to help identify these conditions to allow for special design considerations.
Considerations Based on Treating Pressure Analysis
a) Christianovitch
Well
High sand concentrations are possible.
24
Leak -off will limit the job size so it is important to use a realistic value for fluid loss coefficient in the design process. 20
The design program chosen should utilize the Christianovitch - Zheltov (Daneshy to provide the most realistic estimate of fracture parameters.
) or a 3-D geometry
b) Perkins and Kern Tvue Well
For this type of well the rate of pressure increase will usually be a function of fluid loss. High fluid loss wells will tend to produce more rapid pressure increases during pumping than low fluid loss wells. Since both the high fluid loss and the rapid pressure increase tend to limit job size and the pumping time available, smaller treatments done at high treating rates should be considered in this case. The Perkins and Kern geometry will probably produce the most accurate simulation, provided the gross fracture height can be closely approximatedwith little error. Penny Tvue Well There are basically two methods to deal with a Penny type well. If there are no barriers available to control the vertical height growth, the only option is to consider a controlled rate treatment with a large pad, and a very conservative proppant schedule. Some very good success has been obtained using a tip screen out design approach with the FRACPAC model for these wells. The approach has been to use very conservative proppant concentrations early in the job until a tip screen out is initiated and followed by higher concentrations as the net pressure increases due to the progressing screen out. It is not uncommon to pump a significant quantity of proppant after the screen out has been initiated. This type of treatment will help provide the best possible results given the large fiacture heights and widths typical in a Penny type well.
-
d) Medlin
Another option that may be considered if there are barriers at some large height or if a massive formation is being treated, is to design a high rate high viscosityjob. In this case, the rate and viscosity are used to establish height to a point where fiacture containment can be obtained. Such a treatment would require a large pad volume to first establish adequate width to place the proppant. This option must be ruled out, however, if there is any possibility of fracturing into underlaying water or overlaying gas that could destroy the success of the treatment if broken into. Well Since Medlin type wells are associated with heterogeneous formation conditions such as natural fractures, faults abnormal stress profiles, it is very to make general recommendations to improve treatment design. When these conditions are anticipated it is important to conduct tests designed to show the type of well response and also provide information as to the most effective treatment design. One problem associated with conducting large minifiac tests on these wells is that the pressure increases seen during pumping tend to coincide directly with increasing In many of these wells the increased will not bleed down to values seen earlier in the treatment, even when left for an extended period of time. Assuming that there is some critical pressure increase, conducting reduce the pumping time available for the main treatment. For this reason minifrac tests
25
should be conducted at least the day before the main treatment and the well allowed to flow -back as much as possible in an attempt to relieve the stresses induced during the minifrac treatment. -
Minifrac tests proposed should include a modified step rate test that incorporates a short shut down after each rate increment to record the ISIP and monitor pressure decline. This test should also incorporate at least two different fluid viscosities to test the effects of both rate and viscosity. At least one in test should also be conducted using the fluid desired for the main treatment. Medlin initially found that lower viscosity fluids reduced the rate of pressure increase and allowed larger jobs to be pumped. Results in some wells, however, have shown that high viscosity fluids may reduce the amount of leak -off into natural fractures and significantly reduce the rate of pressure increase by establishing a single more dominant fracture. For this reason it is important to check the effects of different fluid viscosities by using a step rate test combined with a pumpidshut - in test. There are a number of recommendations that can be made depending upon specific well Following is a list of some of these recommendations that should be kept in mind when designing a treatment for a Medlin type well. 1)
e) Nolte
-
Maximize rate.
2)
Try to optimize the fluid viscosity by using minifrac tests. Some wells will respond more favorably to high viscosity fluids while others will respond more favorably to low viscosity fluids.
3)
Use 100 mesh sand during the pad to reduce the fluid loss into natural fractures. Should 100 mesh sand bridge off the natural fractures, it will also have some propping capabilities providing a more conductive natural fracture upon completion of the job.
4)
Use a large pad volume and keep the proppant schedule conservative. Higher strength proppants should be considered as they will provide better long term stability at low concentrations than sand.
5 )
Smaller sized proppants can also help increase the size of the job since they can be transported more easily down a narrow fracture.
6)
In extreme cases the use of a reactive pre-pad of acid can prove to be very helpful in reducing the rate of pressure growth, increasing the job size obtainable.
Well A Nolte type response is usually associated with high rock stresses and natural fractures. In many cases, however, this response can be seen when there is very high fracture entry friction caused by poor perforations or excessive formation damage in the near wellbore region. In acid soluble formations it has been found that the use of a gelled acid pre-pad ahead of the propped fracture treatment can reduce the fracture entry friction, resulting in a drop in treating pressures, followed by a more normal PK or CZ response. In the case of a highly stressed, naturally fractured reservoir the solution is not simple. The presence of high stresses combined with natural fractures tends to produce a combination of
26
high treating pressures and high leak -off, resulting in very poor fracture width development. Consequently, these wells will often begin a screen-out mode the moment that proppant reaches the formation. In this case, it is very to make any major changes that will fix the problem. The following recommendations shouldbe considered in an attempt to improve the proppant placement in these wells. 1)
Large pad volumes.
2)
Use 100 mesh sand to control fluid loss into natural fractures during the pad.
3)
Consider the use of smaller proppant sizes which can be pleased more easily in a narrow fracture.
4)
Use conservative proppant schedules and high strength proppants.
5 )
Conduct a modified step rate test in an attempt to determine the effects of both viscosity on pressure behavior.
rate and
RULES OF THUMB FOR TREATING PRESSURE ANALYSIS Everyone will tend to develop their own procedure for conducting treating pressure analysis. This section formed to help people get off to a good start by providing some basic guidelines, which will help develop a sound procedure to analyze jobs. 1)
Always use a pressure, rate and sand concentration plot in conjunction with the delta P plot. This is important to ensure that pressure trends on the delta P plot are a result of formation response and not a fluctuation of a treatment parameter. In some cases other plots such as additive addition rates may also prove to be very useful when evaluating a delta P plot.
2)
any delta P plot is to try to the type of response A good first step in as described by Conway . In many cases this description, provided with an explanation, may prove to be an adequate analysis.
3)
a standard type curve, a step by step analysis starting at In any treatment that deviates the beginning of the treatment and through to the end of the treatment should be completed. When through a step by step analysis, one should always seek a second opinion prior to writing the report, to ensure that nothing has been missed. It is also important to note job parameters such as rate fluctuations, proppant concentrations, and viscosity changes which may have direct effects on the treating pressures.
4)
If you are ever uncertain about a pressure response it is important to consult with another person who is knowledgeable in pressure analysis to help develop ideas. This can save a great deal of time and frustration.
27
REFERENCES
1.
Nolte, K.G.: "Determination of Fracture Parameters from Fracturing Pressure Decline", paper SPE 8341 presented at the 1979 Technical Conference and Las Nevada, Sept. 23 26.
2.
Nolte, K.G.: "Determination of Proppant and Fluid Schedules from Fracturing Pressure Decline", paper SPE 13278 presented at the 1984 Annual Technical Conference and Exhibition, Houston, Texas, Sept. 16 19.
3.
Martins, J.P. and Harper, T.R.: "Minifrac Pressure Decline Analysis for Fractures Evolving from Perforated Intervals by Confirming Strata", paper SPE 13869 presented at the 1985 Low Permeability Gas Symposium, Denver, Colorado, May 19 - 22.
4.
Lee, W.S.: Decline Analysis with the Christianovitch and Zheltov and Penny Shaped Geometry Model of Fracturing", paper SPE 13 872 presented at the 1985 Low Permeability Gas Symposium, Denver, Colorado, May 19 22.
5.
Lee, W.S.: "Minifrac Analysis Based on Ellipsoidal Geometry", paper SPE 15369 presented at the 1986 Annual Technical Conference and Exhibition, New Orleans, Louisiana, Oct. 5 8.
6.
Lee, W.S.: "New Method of Minifrac Analysis Greater Accuracy and Enhanced Applicability", paper SPE 15941 presented at the 1986 Eastern Regional Meeting, Columbus, Ohio, Nov. 12 14.
7.
Lee, W.S.: "Study of the Effects of Fluid Rheology on Minifrac Analysis ", paper SPE 16916 presented at the 1987 Annual Technical Conference and Exhibition, Dallas, Texas, Sept. 17 30.
8.
Lee, W.S.: "Fracture Propagation Theory and Pressure Decline Analysis with Lagrangian Formulation for Penny Shaped and Perkins and Kern Geometry Models", paper SPE 17151 presented at the 1988 Formation Damage Control Symposium, Bakersfield, California, Feb. 8 9.
9.
Soliman, M.Y.: "Techniquefor ConsideringFluid Compressibility and Temperature Changes in Minifrac Analysis", paper SPE 15370 presented at the 1986 Annual Technical Conference and Exhibition, New Orleans, Louisiana, Oct. 5 8.
10.
Shelly, R.F. and J.M.: Test Correlation Predicts Proppant Placement", paper SPE 15151 presented at the 1986 Rocky Mountain Regional Meeting, Billings, Montana, May 19 21 .
11.
Tan, H.C. J.M., Lee, W.S. and Soliman M.Y.: "Field Application of Minifrac Analysis to Improve Fracture Treatment Design", paper SPE 17463 presented at the 1988 SPE California Regional Meeting, Long Beach, California, March 23 25.
28
12.
P. H.J. : "Analysis of Minifrac Shut-in Pressures, Timber Area, Alberta", paper 90-44 presented at 1990 The International Technical Meeting, Calgary, Alberta, June 10 13.
13.
N.R.: "Dual Leak -off Behavior in Hydraulic Fracturing of Tight, Lenticular Gas Sands", paper SPE 18259 presented at the 1988 Annual Technical Conference and Exhibition, Houston, Texas, Oct. 2 - 5.
14.
Nolte, K.G.: "Fracture Design Consideration Based on Pressure Analysis ", paper SPE 10911 presented at the 1982 Cotton Valley Symposium, Tyler, Texas, May 20.
15.
Nierode, D.E.:"Comparison of Hydraulic Fracture Design Methods to Observed Field Results", paper SPE 12059 presented at the 1983 Annual Technical Conference and Exhibition, San Francisco, California, Oct. 5 8.
16.
Medlin, W.L. and Fitch, J.L.: "Abnormal Treating Pressures in Treatments", paper SPE 12108 presented at the 1983 Annual Conference and Exhibition, San Francisco, California, Oct. 5 8.
17.
Conway, M.W., J.M., Gunderson, D.W. and King, D.G.: "Predictionof Formation Response From Fracture Pressure Behavior ", paper SPE 14263 presented at the 1985 Conference and Exhibition, Las Nevada, Sept. 22 25.
18.
N.R. and Teufel, L.W.: "Influence of Geological Discontinuities on Hydraulic Fracture Propagation", paper SPE 13224presented at the 1987 Annual Technical Conference and Exhibition, Houston, Texas, Sept. 16 19.
19.
R.J. and Batchelor, A.S.: "In-Situ Stresses and Jointing in the Carnmenellis Granite and The Implications for Hydraulic Behaviour", School of Mines Journal (1982).
20.
Daneshy, A.A.: "On the Design of Vertical Hydraulic Fractures ", J. Pet. Tech (January, 1973) 83-97.
