Fluid loss
Fluid loss to the formation should be minimum as possible
The overall fluid loss-coefficient will generally be decreased as the polymer concentration is increased.
Acid-soluble calcium carbonate coated with oil-soluble resin is a fluid-loss additive that is effective in oil wells. An acid overflush is used to dissolve the calcium carbonate.
Low fluid loss is claimed as one significant advantage of foams
1-Proppant transport
The fracture height used in production calculations is not the created height, but the created height less the distance that the proppant settles.
If the fluid is selected so that proppant settling is minimal (less than 8-10 m during the injection and closure period) then essentially perfect suspension is achieved.
2-Compatibility with formation fluids
Very little mixing between the resident water and the fracture fluid is anticipated.
If one water is rich in divalent anion and the other in divalent cation, then some difficulty with compatibility may be expected.
3-Formation damage
The fluid loss into the formation adjacent to the fracture will result in formation damage.
In most cases, the damage to the formation adjacent to the fracture surfaces will not be severe enough to influence production.
To prevent formation damage
It is recommended that the fracture fluid contain at least 2 wt% KC1 Fresh water without added salts should be avoided.
Surfactants should not be added to fracture fluid for oil well application without supporting laboratory work to demonstrate that oil/water emulsions are made less stable if the surfactant is added.
For gas wells, addition of surface tension reducing surfactants is recommended.
Lowering the surface tension will reduce capillary pressure effects and be beneficial.
Surfactants used in this application should be quite water soluble at the bottomhole condition and should be applied at concentrations well above the critical micelle concentration.
Design of Proppant Fracturing Treatments
The design strategy for optimizing the fracture treatment once it has been decided to fracture must evidently include economic considerations.
We will not carry the procedure out to the extent that the return on investment is calculated, since all of the factors including :
1-Interest rates
2-Oil or gas prices
3-Taxes
4-Treatment costs
The technical problem of optimizing fracture design can , however, be separated from the economic aspects if the procedure recommended here is followed.
The first step is to select the amount and type of proppant to be used. This is equivalent to specifying the "size" of the treatment. Once the amount of a certain proppant is selected, the fracture length is fixed.
The next task is to select a fluid that can transport and suspend the proppant to the extent necessary as well as create the desired fracture geometry.
Optimum fracture length
If M0 is the selected amount of proppant, then for uniform coverage the proppant surface concentration is given by
Fluid loss to the formation should be minimum as possible
The overall fluid loss-coefficient will generally be decreased as the polymer concentration is increased.
Acid-soluble calcium carbonate coated with oil-soluble resin is a fluid-loss additive that is effective in oil wells. An acid overflush is used to dissolve the calcium carbonate.
Low fluid loss is claimed as one significant advantage of foams
1-Proppant transport
The fracture height used in production calculations is not the created height, but the created height less the distance that the proppant settles.
If the fluid is selected so that proppant settling is minimal (less than 8-10 m during the injection and closure period) then essentially perfect suspension is achieved.
2-Compatibility with formation fluids
Very little mixing between the resident water and the fracture fluid is anticipated.
If one water is rich in divalent anion and the other in divalent cation, then some difficulty with compatibility may be expected.
3-Formation damage
The fluid loss into the formation adjacent to the fracture will result in formation damage.
In most cases, the damage to the formation adjacent to the fracture surfaces will not be severe enough to influence production.
To prevent formation damage
It is recommended that the fracture fluid contain at least 2 wt% KC1 Fresh water without added salts should be avoided.
Surfactants should not be added to fracture fluid for oil well application without supporting laboratory work to demonstrate that oil/water emulsions are made less stable if the surfactant is added.
For gas wells, addition of surface tension reducing surfactants is recommended.
Lowering the surface tension will reduce capillary pressure effects and be beneficial.
Surfactants used in this application should be quite water soluble at the bottomhole condition and should be applied at concentrations well above the critical micelle concentration.
Design of Proppant Fracturing Treatments
The design strategy for optimizing the fracture treatment once it has been decided to fracture must evidently include economic considerations.
We will not carry the procedure out to the extent that the return on investment is calculated, since all of the factors including :
1-Interest rates
2-Oil or gas prices
3-Taxes
4-Treatment costs
The technical problem of optimizing fracture design can , however, be separated from the economic aspects if the procedure recommended here is followed.
The first step is to select the amount and type of proppant to be used. This is equivalent to specifying the "size" of the treatment. Once the amount of a certain proppant is selected, the fracture length is fixed.
The next task is to select a fluid that can transport and suspend the proppant to the extent necessary as well as create the desired fracture geometry.
Optimum fracture length
If M0 is the selected amount of proppant, then for uniform coverage the proppant surface concentration is given by
Given the total amount of proppant, there exists an optimum fracture length which maximizes the stimulation ratio.
Selection of a fracture fluid
Generally, this is a trial-and-error process. If the fracture length is long, then fluids which maintain their viscosity at the reservoir temperature for several hours may be required. For relatively short fractures the entire process may require less than one hour and therefore, the polymer concentration can be reduced.
Having selected a fluid for consideration, one must ensure that both the desired fracture geometry can be created and the proppant transporting capabilities are satisfactory.
If one or both of these conditions are not satisfied, the entire calculation must be repeated until a fluid is found which just satisfies them.
Injection schedule
A fracture treatment is generally initiated by first injecting water containing small quantities of polymer selected so as to reduce the friction pressure.
This fluid is sometimes called slick water. Its viscosity is essentially that of water and it readily invades the formation surrounding the wellbore, thereby increasing the pore pressure.
This situation is helpful in initiating a fracture; that is, in "breaking down" the formation..
Following the slick water, the polymer solution is injected but proppant is not immediately added. This fluid which contains polymer but not proppant is called a pad fluid and the volume of this fluid that is injected is called the pad volume.
The purpose of the pad volume is to create a fracture of sufficient width and length so that when proppant is introduced, it can be freely transported along the fracture.
It is not desirable for proppant to reach the end of the fracture because the fracture narrows sharply at the end and proppant particles could conceivably bridge across the width of the fracture, thereby prematurely terminating proppant transport down the fracture.
The injection schedule is simply a listing of the total volumes and compositions of each of the stages of a fracture treatment.
To resolve this issue it is useful to be able to track the movement of a particle as it progresses down the length of a fracture. In particular, we would like to know the time at which the fluid element occupying the position x at time t was injected.
Practical Considerations in Designing Fracture Treatment
Pumping rate
The fluid injection rate is an important design parameter that should be as large as possible. It is, however, limited by the strength of wellhead and tubular goods.
Fracture height.
It is often better to overdesign a treatment until the fracture height normally created in a particular formation can be established or until measurements of the in-situ stresses as a function of depth are available.
If the in-situ stresses are known, then the design can be carried out using a three-dimensional fracture simulator.
Fluid diversion
In thick horizons it may be necessary to fracture isolated sections or to attempt to divert the fluid from one zone to another by plugging perforations during the course of a treatment.
Diverting of fracture fluid during proppant fracturing is not desirable and can obviously lead to difficulties.
Fluid loss
Knowledge of the fluid loss coefficient is critical.
Excessive fluid loss can lead to premature bridging of the proppant across the fracture and ultimate "sand out."
A buildup of proppant within the fracture or at the wellbore will be signaled by a sudden increase in surface pressure, forcing premature ter¬mination of the treatment.
"Sand out" is most often a result of poor fluid loss control.
In new formations the design should include a safety factor (large pad volume) to ensure that the proppant is placed.
Acid fracturing
The mechanism by which permanent conductivity is achieved by acid fracturing differs entirely from that of proppant fracturing.
The important length is the distance that acid moves along the fracture before it has been completely reacted (spent).
This distance is a function of many factors including :
1. The acid fluid loss characteristics
2. The rate of acid reaction with the rock
3. The fracture width
4. The acid injection rate.
Increasing the fracture width can significantly increase the acid penetration distance. This is true because live acid must diffuse from the center of the fracture to the fracture wall before it can react. We simply note that the process of molecular diffusion in liquids is a slow one as compared to the reaction rate of carbonates with hydrochloric acid and by widening the fracture, the rate of overall reaction is slowed. This means that wide acid fractures are required to obtain deep penetration distances
The penetration distance also increases with acid injection rate as a result of the shorter residence time for reaction. However, in practice, increasing the rate will increase the fracture width and thus change the residence time in a complex way. However, increasing the flow will generally lead to increased acid penetration distances.
The acid penetration distance is almost independent of temperature in limestone but depends on the temperature in dolomites.
The reaction rate of hydrochloric acid with limestone is an extremely rapid one even at low temperatures; thus, increasing the temperature only serves to increase an already fast reaction and does not alter the penetration distance
The reaction of dolomite with hydrochloric acid is slower than that of limestone and at low temperatures the finite reaction rate slows acid spending, permitting deeper penetration. As the temperature is increased, the rate of reaction increases and at sufficiently high temperatures (>70°C) there is little, if any, difference in the acid penetration distance between limestone and dolomite.
Design and optimization of fracture processes
The final design will be best in some economic sense and requires different considerations.
Acid fracturing
For acid fracturing the amount acid to be used in treatment will be fixed
This fixed amount of acid will in turn fix the optimum fractures length
1 Selection of fracture fluid and additives
2 Design of acid fractures
Either an is acid injected alone into the formation or an acid preceded by a viscous pad fluid to form a wide, deep fracture.
The viscous pad will generally contain suitable flow loss control agent such as 100 mesh sand.
Fluid loss control Additives
Such as:-
1. Oil-soluble resins
2. Silica flour
3. 100 mesh sand.
4. Other additives that are blended with acid
Corrosion inhibitors :
To protect the metal from acid attack
Emulsion breaking surfactants:
Useful for avoiding emulsions that tend to form when the acid and formation fine material mix with formation oil.
Friction reducers:
Reduce friction losses through the well.
Design of acid fractures
The basics of acid fracturing treatment design are similar to proppant fracturing treatment design in that the size of the treatment is dictated by economics.
Acid fracturing treatment are easier to design because of the limited choice of fluid and because of the limited control over the fracture conductivity.
Given an acid volume there is an optimum length.
The short fracture has high fracture conductivity since, the more rock dissolved the greater will be the fracture conductivity.
The long fracture has a smaller fracture conductivity since less rock is dissolved within a given fracture area.
Thus if the volume of acid is specified the volume of rock which can be dissolved is fixed.
Sketch depicting two different fractures both created with the same volume of acid
Optimum fracture length is selected so that a fracture of uniform conductivity maximizes the stimulation ratio.
A uniform conductivity implies that rock is dissolved uniformly over the entire fracture surface.
With acid it is not possible to achieve a perfectly uniform conductivity because acid concentration is highest at the wellbore so the fracture conductivity will be greater near the wellbore and decrease with increasing distance
Generally, this is a trial-and-error process. If the fracture length is long, then fluids which maintain their viscosity at the reservoir temperature for several hours may be required. For relatively short fractures the entire process may require less than one hour and therefore, the polymer concentration can be reduced.
Having selected a fluid for consideration, one must ensure that both the desired fracture geometry can be created and the proppant transporting capabilities are satisfactory.
If one or both of these conditions are not satisfied, the entire calculation must be repeated until a fluid is found which just satisfies them.
Injection schedule
A fracture treatment is generally initiated by first injecting water containing small quantities of polymer selected so as to reduce the friction pressure.
This fluid is sometimes called slick water. Its viscosity is essentially that of water and it readily invades the formation surrounding the wellbore, thereby increasing the pore pressure.
This situation is helpful in initiating a fracture; that is, in "breaking down" the formation..
Following the slick water, the polymer solution is injected but proppant is not immediately added. This fluid which contains polymer but not proppant is called a pad fluid and the volume of this fluid that is injected is called the pad volume.
The purpose of the pad volume is to create a fracture of sufficient width and length so that when proppant is introduced, it can be freely transported along the fracture.
It is not desirable for proppant to reach the end of the fracture because the fracture narrows sharply at the end and proppant particles could conceivably bridge across the width of the fracture, thereby prematurely terminating proppant transport down the fracture.
The injection schedule is simply a listing of the total volumes and compositions of each of the stages of a fracture treatment.
To resolve this issue it is useful to be able to track the movement of a particle as it progresses down the length of a fracture. In particular, we would like to know the time at which the fluid element occupying the position x at time t was injected.
Practical Considerations in Designing Fracture Treatment
Pumping rate
The fluid injection rate is an important design parameter that should be as large as possible. It is, however, limited by the strength of wellhead and tubular goods.
Fracture height.
It is often better to overdesign a treatment until the fracture height normally created in a particular formation can be established or until measurements of the in-situ stresses as a function of depth are available.
If the in-situ stresses are known, then the design can be carried out using a three-dimensional fracture simulator.
Fluid diversion
In thick horizons it may be necessary to fracture isolated sections or to attempt to divert the fluid from one zone to another by plugging perforations during the course of a treatment.
Diverting of fracture fluid during proppant fracturing is not desirable and can obviously lead to difficulties.
Fluid loss
Knowledge of the fluid loss coefficient is critical.
Excessive fluid loss can lead to premature bridging of the proppant across the fracture and ultimate "sand out."
A buildup of proppant within the fracture or at the wellbore will be signaled by a sudden increase in surface pressure, forcing premature ter¬mination of the treatment.
"Sand out" is most often a result of poor fluid loss control.
In new formations the design should include a safety factor (large pad volume) to ensure that the proppant is placed.
Acid fracturing
The mechanism by which permanent conductivity is achieved by acid fracturing differs entirely from that of proppant fracturing.
The important length is the distance that acid moves along the fracture before it has been completely reacted (spent).
This distance is a function of many factors including :
1. The acid fluid loss characteristics
2. The rate of acid reaction with the rock
3. The fracture width
4. The acid injection rate.
Increasing the fracture width can significantly increase the acid penetration distance. This is true because live acid must diffuse from the center of the fracture to the fracture wall before it can react. We simply note that the process of molecular diffusion in liquids is a slow one as compared to the reaction rate of carbonates with hydrochloric acid and by widening the fracture, the rate of overall reaction is slowed. This means that wide acid fractures are required to obtain deep penetration distances
The penetration distance also increases with acid injection rate as a result of the shorter residence time for reaction. However, in practice, increasing the rate will increase the fracture width and thus change the residence time in a complex way. However, increasing the flow will generally lead to increased acid penetration distances.
The acid penetration distance is almost independent of temperature in limestone but depends on the temperature in dolomites.
The reaction rate of hydrochloric acid with limestone is an extremely rapid one even at low temperatures; thus, increasing the temperature only serves to increase an already fast reaction and does not alter the penetration distance
The reaction of dolomite with hydrochloric acid is slower than that of limestone and at low temperatures the finite reaction rate slows acid spending, permitting deeper penetration. As the temperature is increased, the rate of reaction increases and at sufficiently high temperatures (>70°C) there is little, if any, difference in the acid penetration distance between limestone and dolomite.
Design and optimization of fracture processes
The final design will be best in some economic sense and requires different considerations.
Acid fracturing
For acid fracturing the amount acid to be used in treatment will be fixed
This fixed amount of acid will in turn fix the optimum fractures length
1 Selection of fracture fluid and additives
2 Design of acid fractures
Either an is acid injected alone into the formation or an acid preceded by a viscous pad fluid to form a wide, deep fracture.
The viscous pad will generally contain suitable flow loss control agent such as 100 mesh sand.
Fluid loss control Additives
Such as:-
1. Oil-soluble resins
2. Silica flour
3. 100 mesh sand.
4. Other additives that are blended with acid
Corrosion inhibitors :
To protect the metal from acid attack
Emulsion breaking surfactants:
Useful for avoiding emulsions that tend to form when the acid and formation fine material mix with formation oil.
Friction reducers:
Reduce friction losses through the well.
Design of acid fractures
The basics of acid fracturing treatment design are similar to proppant fracturing treatment design in that the size of the treatment is dictated by economics.
Acid fracturing treatment are easier to design because of the limited choice of fluid and because of the limited control over the fracture conductivity.
Given an acid volume there is an optimum length.
The short fracture has high fracture conductivity since, the more rock dissolved the greater will be the fracture conductivity.
The long fracture has a smaller fracture conductivity since less rock is dissolved within a given fracture area.
Thus if the volume of acid is specified the volume of rock which can be dissolved is fixed.
Sketch depicting two different fractures both created with the same volume of acid
Optimum fracture length is selected so that a fracture of uniform conductivity maximizes the stimulation ratio.
A uniform conductivity implies that rock is dissolved uniformly over the entire fracture surface.
With acid it is not possible to achieve a perfectly uniform conductivity because acid concentration is highest at the wellbore so the fracture conductivity will be greater near the wellbore and decrease with increasing distance
Fluid loss
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