Oil well Stimulation con't 4(Sandstone Acidizing)


Fluids Available
Hydrochloric acid
Preflush
Overflush
Hydrofluoric acid systems
Mud Acid
Organic Mud Acid
Clay Acid
Organic Acids
Formic
Acetic
Citric (L1)

Selection Criteria
Formation mineralogy
Sensitivity
Deconsolidation
Precipitation
Fines release
Reactivity
Chemical composition
Surface area
Rock Structure
HCl solubility / carbonates
Clay distribution
Preflush - Brine
Ammonium chloride
Minimum spacing at any moment between formation brine and HCl
      3 wt% (<5% Clay)
      4 wt% (5-10%)
      5 wt% (10-15%)
      6 wt% (>15%)
Main Acid - Volume
1      Target: skin reduction
2      Never zero
3      Minimum skin achievable: pseudoskin value
4      Maximum reduction: 90%
Systems Available
Mud Acid
Organic Mud Acid
Clay Acid
Organic Clay Acid

Mud Acid
1      Nine HCI-HF formulations in MA selection Guide
2      Dissolves siliceous minerals
3      Dowell offered the first commercial Mud Acid Service in 1940 in the (U.S. Gulf Coast)
Mud Acid Reaction Simplified Version
Organic Mud Acid
1      Formic acid (9% L036 replaces 12% HCl)
2      Less corrosive than comparable Mud Acid formulations
3      Reaction rate ~ 1/4 that of Mud Acid
4      Reduces sludged tendency
Organic Mud Acid Preparation
Dissolving Y-1 (Ammonium Bifluoride) in HCl solution
Add enough HCl to completely react with Y-1
Add L36 last
Blending 20% HF (H200) and L36 into fresh water
Clay      Acid:
a retarded Mud Acid
Improved Penetration with Clay Acid
Clay Acid & Mud Acid
1      Preflush to Mud Acid: sensitivity
2      Main Acid: carbonate-cemented, long MA treatments
3      Overflush to Mud Acid: enhanced clay control
4      Shut-in and bring production back slowly

Primary Reaction – What to do ?
Alkali compounds
              1.     Push away formation brine
              2.     Brine with no Na, K, Ca
                      Ammonium Chloride Brine
CaF2
                      Dissolve CaCO3
                      HCl Preflush
Secondary Reaction – What to do ?
AlFx
                      Maintain a low-pH environment
                     
Silica Gel
                      Maintain a low-pH environment

                       Include HCl in HF treatment (Mud Acid)
Tertiary Reaction – What to do?
AlFy

              1.     Maintain a low-pH environment
                      pH > 2.5 a problem
May be localized in the formation
              2.     Overdisplace fluids         

                              HCl overflush
Matrix Stimulation: Carbonate
Kinetics of HCl Reaction
Mass-Transfer-Limited
Key Factors in Carbonate Acidizing
1.  Penetration
2.   Acid reactivity
3.   Injection rates
4.   Diversion
Injection Rates: dissolution patterns
Patterns change depending on:
Temperature
Injection velocity
Surface reaction rate
Impact of Pump Rate and Temperature
Reaction rate can be too high even with Organic Acids at high temperature.
Core entrance after 15%  HCl flow
Wormhole Pattern from Radial Flow
Pore Level Model

Oil well Stimulation con't 3 ( Matrix Acidizing)


1      Matrix acidizing is  a well  stimulation technique in which an acid is injected into the formation in order to dissolve some of the minerals present and hence increase permeability in the near-wellbore vicinity.
What is the difference between matrix acidizing and acid fracturing?
In matrix acidizing ,the acid is injected at pressure below the fracture pressure of the formation while in acid fracturing the acid injected at pressure above the formation fracture pressure.
Treating techniques:
1-Uncontrolled Acidizing:
A-Remove fluid standing in the hole by swabbing
B-Pump the acid into the casing
C-Follow the acid with sufficient displacement fluid to force all the acid out into the formation
Advantages of uncontrolled acidizing:
1-It is cheaper
2-Less time consuming
3-The reaction products are readily removed from the formation


Its disadvantages:
There is no control over where the acid will go and it is possible for the fluid to be wasted on an unproductive zone.
2-Selective acidizing: the acid is directed into a desired section of the formation
A-Conventional Method:
1-The well is filled with oil followed by the acid to displace the oil in the tubing, plus the annulus.
2-Then casing outlet is closed then.
3-Further pumping of acid results in the acid’s being forced out into the formation.
B-The packer method:
1-The well is filled with oil, after which acid is pumped down the tubing and spotted over the pay zone
2-The packer then prevent further travel of the acid up the annulus of the well and is forced out into formation.
C-The selective electrode technique
1-Tubing is lowered so that the seating nipple is opposite the zone and acidizing electrode is run on wire line and seated in the nipple.
2-The acid-oil interface is kept at any desired position by the use of two pumps, one pumping acid down the tubing, the second pumping oil down the annulus.
3-The level of the interface is determined electrically at the surface.

D-Radioactive-tracer Technique
In this case, a small amount of radioactive isotope is dissolved in the acid, and the level of the acid-oil interface in the annulus is detected by Geiger counter hung on a wire line in the tubing.
E-Ball sealers
It is possible to acidize the less permeable section by dropping ball sealers.
These ball sealers enter the more permeable section, wedge these balls into the perforations and divert the acid into the less permeable zone.
F-Temporary Plugging Agents
Selective acidizing either in perforated casing or open hole may be accomplished by the use of temporary chemical plugs which block off the most permeable section.
The materials used are self liquefying, either by interaction of two or constituents or by dissolution in the well fluids.
Selective Acidizing
 Advantage
1-Keeping the acid out of unproductive zones
2-Stimulate tight section
3-Preventing the acid from entering water zones
Disadvantages
1-More expensive   2-The treatment is difficult to conduct
3-Longer time is required for the well to clean up afterwards.
Stage Acidizing
The well is treated with two or more separate stages of acid, rather than one stage.
At the first stage, we clean up the contaminated zone near the wellbore so that later stages can penetrate further distances.
Chemicals
1-Acids
HCL is used usually for acidizing in oil fields
In case of sulfuric acid, the reaction product calcium sulfate being insoluble and remaining in the formation, plugging flow passages.
Other acids such as acetic acid and citric acid have been used, but their high cost limits their use.
2-Inhibitors
Inhibitors are chemical materials which greatly retard the reaction rate of the acid with metals.
Their use is to avoid damage to casing, tubing, pumps and valves
Their use only slow the reaction down, eliminating 95 to 98 percent of the metal loss
3-Intensifiers
Intensified acid is admixtures of inhibited hydrochloric and hydrofluoric acids.
The fluoride present speeds up the reaction rate of the acid and enable the acid to dissolve insoluble minerals found in dolomite in small amounts.
4-Surfactants
Surfactants lower the surface tension of acid solution.
The presence of surfactant facilitates the penetration of the acid solution into the microscopic formation.
Another advantage is the demulsifying action of it which inhibits the occurrence of emulsions.
5-Demulsifiers
When the crude oil is mixed or agitated with acid or spent acid, emulsions may be formed which could block the formation.
Demulsifies are chemical agents which counteract the natural emulsifiers in the crude oil.
6-Silicate Control
These silicates will swell in spent acid and hence swollen silicate particles may block.

The silicate control agents either:
1-Keep the acid pH at a definite value at which silicate particles occupies the smallest volume
2-Causing shrinkage of the silicate particles by replacing the adsorbed water molecules with a water repellant organic film

7-Hot Acid
By heating the acid, the reaction rate is increased and amore effective treatment result.
 It is better to heat the acid at the bottom of the wellbore.
This is accomplished by allowing the acid to react with magnesium at bottom.
8-Fluid Loss Control
Special additives are available which are designed to prevent “bleeding off "of acid into small formation pores.
The additives consist of ground vegetable material which blocks the finer pores but is later destroyed by hydrolysis.
9-Iron Retention
The iron compounds which are dissolved will re-precipitate as a bulky, gelatinous hydroxide when the acid becomes spent.
Various complexing agents are used to tie up the dissolved iron in complex ions, retaining it in solution even after the acid has become spent.

Precipitation of acid reaction products:
The most common damaging precipitates in sandstone acidizing are:
1-Calcium fluoride:
 It results from reaction between HF and Calcite.
Inclusion of an adequate HCL preflush ahead of the HF/HCL stage prevents its formation.
2-Colloidal silica:
Its precipitation occurs at fairly slow rate.
To minimize its damage, we inject the acid at high rates, so that the precipitation zone is rapidly displaced away from the wellbore.
Also, spent acid should be produced back.


3. Ferric hydroxide:
The ferric ions precipitate from spent acid solution when the pH is greater than 2.
The ferric ions result from the dissolution of rust in tubing by the acid solution.
4-Asphaltene sludge:
The contact of crude oil by acid causes their formation.
Surface active additives have been used to prevent their precipitation.

Oil well Stimulation con't 2

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




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
 
Fluid loss