Production Test 2

Injection & Disposal wells + MSHF + Acid Stimulations

Is cementing production casing to surface a requirement for all disposal/injection wells?

No

• Directive 51 states: For all well classes, if the production casing is not cemented to surface or cement returns to surface are not obtained and maintained during setting, then a cement top locating log must be run.

What are the four (4) common types of logs required to determine hydraulic isolation? Is there a choice as to which to run?

• Temperature survey

• Radioactive tracer survey

• Oxygen activation log

• Cement integrity log

Yes, operators may choose one of the three isolation logs (in addition to the temperature survey), except where Class Ia gas-injection rules apply (must include a cement integrity log).

Can logging requirements be waived? What are the primary criteria for a waiver?

Yes

A. Casing Inspection Log Waiver

• Only considered for wells less than five years old.

B. Hydraulic Isolation Log Waiver

• Only considered for wells accepting fluid on vacuum

• Waivers not normally granted for Class Ia or Ib wells.

C. Cement Top Locating Log Waiver
Supported by:

• open‑hole caliper

• slurry volumes

• cement logs from nearby wells

• cementing program records and evidence of good returns

• cement top evidence in adjacent wells with similar cementing programs

Is analysis of offset wells a requirement for hydraulic isolation testing? For what purpose?

Analysis of offset wells is required as supporting evidence when seeking waivers

What are the requirements for casing integrity determination?

• Casing inspection log must be run

• Minimum burst resistance requirements must be met

• Corrosion rate acceptability limits must be met

________ ___________ wells are purposely completed in formations that are known to be largely devoid of hydrocarbons and that are naturally charged with brackish water or non-commercial volumes of natural gas

Water disposal

TorF: Water disposal wells are often porous and highly permeable

True

• this allows them to have high volumes of water injected into them

TorF: Salt caverns created by the salt extraction industries are the most common type of water disposal well

False

By what multiplier must minimum yield strength of casing exceed the maximum allowable wellhead injection pressure?

1.3

• Directive 051 requires that the minimum internal yield pressure of the casing be at least 1.3 times the maximum allowable wellhead injection pressure

What are the specifications for rate of casing corrosion in wells to be converted to disposal/injection?

Corrosion is unacceptable if an anomaly exhibits:

• > 20% wall loss in 5 years

• > 40% wall loss in 10 years

• > 60% wall loss in 15 years

Are certain fluids prohibited from being injected or disposed of in sub-surface formations? Can clean rainwater runoff be injected?

Directive 051 lists several categories of fluids that are prohibited:

• Municipal or industrial sewage

• Surface water runoff that meets surface discharge criteria or could meet them without cost‑prohibitive treatment

• Lube oils and spent solvents

• Hydrocarbon‑based drilling fluids

• Waste with available suitable treatment technology

Clean rainwater runoff cannot be injected.

What are the existing classes of injection wells?

• Describe each

Class II, III and IV are used for injection

• Class II → Injection of Produced Water or Brine

• Class III → Injection of Hydrocarbons or Gases

• Class IV → Injection of Useable Water or Steam

What are the existing classes of disposal wells?

• Describe each

Class 1a and 1b

• Class 1a → Highest‑risk category of subsurface disposal wells.

  • Used for the disposal of industrial or complex oilfield waste streams that exceed Class Ib criteria

• Class 1b → disposal of common, lower‑risk oilfield waste fluids

For an open hole MSHF job in which the wellbore is off-gauge, what type of packer would be used, mechanical or swelling?

Swelling

TorF: For an open hole packer and sliding sleeve (ie. ball drop) system, the service rig must remain on site in order to remove the packers once the fracturing job is complete.

False

• The packers stay in the hole

• The service rig can be rigged out once the packer/sleeve system is installed as there are no plugs to remove

  • The balls are simply flowed back (or dissolved if dissolvable balls are used) when the well is placed on production and trapped in a ball catcher installed on the flowback equipment

Which of the following MSHF systems allows for one continuous pumping operation with no requirement for shutdown between fracture stages?

a) Open hole packer and sleeve (ball drop)

b) Plug and perf

c) both a and b

d) none of the above

a) Open hole packer and sleeve (ball drop)

• Ball‑drop sliding‑sleeve systems are specifically designed to enable continuous pumping with no shutdowns between stages

  • Each stage is opened by dropping a ball, allowing stimulation to proceed uninterrupted

Describe how a open hole packer and sleeve system is installed downhole prior to fracturing operations.

Multiple packers and sliding sleeves are run on jointed tubing in an open hole lateral section.

• The entire packer/sleeve system is installed from toe to heel and tied back to the cemented casing prior to fracturing.

In an open hole packer and sleeve system, how are the sleeves activated so that a given stage can be fraced?

The sleeves are activated by dropping composite (i.e. synthetic) balls that seat in the packer/sleeve assemblies and allow fluid pressure to shift the sleeve open.

• The fracture treatment is then pumped through the open sleeve.

TorF: Class 1b wells are used for the disposal of high risk waste fluids

False

• Class 1a wells are used for disposal of high risk waste fluids

• Class 1b is for disposal of common, low-risk waste fluids

What does MSHF stand for?

Multi-stage hydraulic fracturing

Name the 3 main types of multistage hydraulic fracturing systems currently used in the industry

1. Plug and perf

• most common for cased hole completions

2. Ball drop activated sliding sleeve

• most common for open hole completions

3. Coiled tubing activated systems

What type of MSHF system would be used in an open hole completion?

a) plug and perf

b) packer and sleeve system

c) coiled tubing activated system

b) packer and sleeve system

Describe 2 cases in which a CT activated system would be the preferred MSHF method

1. Highly deviated or tortuous well paths

2. Want to retain the option of re-entry/re-fracing of stages

For extended reach laterals, which MSHF method would be preferred? Why?

Ball activated sliding sleeves

• Avoids the wireline and CT limitations in long laterals

  • Wireline runs become slow, difficult, and risky at extreme lateral lengths

  • With CT, friction, buckling, and lock‑up risk increase drastically with lateral length

• Enables continuous pumping and high stage counts

  • removes the need for repeated wireline runs, which become time‑prohibitive in long horizontals

NOTE: The Packers Plus StackFRAC HD‑X system was designed for extended‑reach laterals and successfully completed 49–50 stages in ~10,000‑ft laterals with 100% ball‑drop success

Where formation integrity may be an issue, which of the following MSHF systems would be employed?

a) open hole ball drop activated sleeves

b) cased hole plug and perf

b) cased hole plug and perf

TorF: Typically, stages are stimulated from heel to toe in most MSHF systems

False

• Toe to heel

In a ball drop activated sliding sleeve system, which would be dropped first, the smaller balls or the larger balls?

The smaller balls are dropped first

• Because the smallest seat is at the toe, the smallest ball must be dropped first so it lands on the smallest seat and opens the first sleeve

  • Larger balls follow afterward to activate the progressively larger seats closer to the heel

    • If you dropped the largest ball first, it would catch in the first seat, blocking off the rest of your stages

TorF: In plug and perf systems, the bridge plugs can be run on wireline or CT

True

TorF: In plug and perf systems using standard composite plugs, the bridge plugs must be removed once the final stage is fractured

True

• They are drilled out (typically with a mill run on CT)

  • Note that the CT itself cannot rotate, but the mill run on the CT is driven hydraulically by fluid pumped down the CT

Note: “standard composite plugs” → non-dissovable

Briefly outline the functioning of plug and perf MSHF systems

Briefly outline the functioning of CT activated MSHF systems

If the wellbore damage is confined to the near wellbore area (ie. skin damage), which stimulation method should be used?

a) Hydraulic fracturing

b) SAGD

c) Matrix acidizing

c) Matrix stimulation

TorF: In matrix acidizing, the injection pressures must be above the fracture pressure of the formation so that the acid can penetrate the damaged zone and increase permeability near the wellbore

False

• Injection pressures are below fracture pressure

• The dissolving action of the acid (not fracturing) is what breaks down the skin and increases perm to the wellbore

In a ball drop activated sliding sleeve system, is the smallest ball seat at the toe or the heel?

Toe

• if it was at the heel it would catch the first ball you drop and block off the rest of the stages

Name several types of formation damage that can be addressed using acid stimulation

• Clay

• Paraffin and asphaltenes

• Emulsions

• Wettability issues

• Scale

• Particulate damage

Which class of injection well is used in SAGD operations?

Class IV → usable water and steam injection

TorF: For a ball drop MSHF system on an open hole completion, a packer must be used at the casing shoe of the nearest casing string

True

• This packer is placed above the heel and isolates the tubing/casing annulus so that the tubing/open hole annulus in the lateral can be pressured up while isolating the wellbore region above the packer from the frac pressures

Name the 4 most common clays that can potentially lead to formation damage

1. Kaolinite

2. Smectite

3. Illite

4. Chlorite

To recover the highest amount of hydrocarbons, most treatments aim to change the formation to __________

a) water-wet

b) oil-wet

c) Neutral

a) water-wet

• In a water‑wet reservoir, the solid rock surface has a stronger attraction to water molecules than to oil molecules

  • So water forms a thin film along pore walls, and oil occupies the centers of the pores

    • This arrangement reduces the energy required for oil to move

Note: is accomplished by using surfactants

TorF: Calcium sulfate (gypsum) is a type of scale that can be removed by acid.

False

• Calcium sulfate (gypsum) is not acid-soluble

Which of the following can be readily removed by HCl?

a) Calcite

b) Calcium Sulfate

c) Barium Sulfate

d) all of the above

a) Calcite

• Calcium Sulfate (gypsum) → not soluble in acid

• Barium Sulfate → not soluble in acid

  • must be removed mechanically

TorF: Matrix acidizing is an effective method to aid in yielding a stimulated skin (ie. S<0)

False

• Matrix acidizing will only succeed in returning the skin to a neutral state (S=0) and will not aid in yielding a stimulated skin (S<0)

Note that the above is what the module says, whereas in the Haliburton Matrix Acidizing PDF it claims that “acid treatments in sandstones only remove damage, while acid treatments in carbonates remove damage and stimulate the well.”

Name the 4 common acids used in oilfield applications

• Hydrochloric acid, HCl

• Hydrofluoric-hydrochloric acid blends, HF-HCl

• Acetic Acid, CH₃COOH

• Formic Acid, HCOOH

What is the most common acid type used in oilfield applications?

15% HCl

If a more aggressive acid is required than 15% HCl, what would typically be added to the HCl?

HF (Hydrofluoric acid)

TorF: HCl alone is an effective acid treatment for sandsstone reservoirs

False

• HCl dissolves calcite, and so is used in carbonate (limestone and dolomite) reservoirs

For sandstone reservoirs with little calcium, HF is used along with HCl

Name several types of acid additives

• Clay control

• Iron control

• Anti-sludge

• Surfactants

• Corrosion inhibitors

• Alcohols

What kind of damage does iron pose to an acid job? How can this be mitigated?

Iron caused precipitation and sludge formation

• pickling is used to remove rust and mill scale to reduce iron pickup by the main treatment

Which of the following would be used to remove contaminants in the tubing to ensure that they are not injected into the reservoir rock:

a) Acid wash

b) Pickle

c) Matrix acid job

d) Acid diversion

b) Pickle

• used to remove iron, pipe dope, scale, etc. from tubing prior to injecting acid into the zone

TorF: Acid from a tubing pickling can sometimes contact for the formation, but this is not a real concern as the subsequent acid treatment will remove any contaminants

False

• Acid from the tubing pickle should never contact the formation

  • Pickling acid will contain iron, corrosion products, mill scale, rust, oils, and tubing contaminants

    • This cannot be pushed into the formation as it cannot be reliably removed by the subsequent acid job

TorF: In a tubing pickle, the procedure is:

a) reverse circulate acid down the tubing annulus and up the tubing

b) circulate acid down the tubing and up the tubing annulus

c) circulate acid down the tubing and then reverse circulate back to surface

d) none of the above

c) circulate acid down the tubing and then reverse circulate back to surface

• This ensures that the pickling acid never contacts the formation

Which of the following would be used to remove acid soluble residue or scale from pumps:

a) Acid wash

b) Pickle

c) Matrix acid job

d) Acid diversion

a) Acid wash

Which of the following would be used to clean up perforations?

a) Acid wash

b) Pickle

c) Matrix acid job

d) Acid diversion

a) Acid wash

TorF: Matrix Acid jobs are often done prior to fracturing

True

• according to the module

In a non-flowing well, how would flow be initiated to flow back the spent acid after an acid stimulation treatment?

Swab the well

TorF: The skin/productivity relationship is nonlinear

True

• reducing skin factor from 5 to 0 has a bigger impact on production than reducing it from 25 to 20

  • recognizing that the skin/productivity relationship is nonlinear is fundamental to effective candidate selection and optimized treatment design

If significant permeability or formation damage variations are present in the interval to be treated, what is done to address this when matrix acidizing?

Diversion methods

• If significant permeability or formation damage variations are present, the acid will enter the zones with the highest permeability or least formation damage, leaving little acid to treat what may be the most productive zones

  • To achieve uniform damage removal, the original flow distribution across the treated interval needs to be altered to provide generally equal acid distribution

    • The methods used to alter this flow distribution are called diversional methods

      • The surest way to uniformly treat an interval is with a mechanical isolation device such as a straddle packer. This packer allows acid to be injected into small intervals, one by one, until the entire zone has been treated.

        • However, this method is often not practical or possible. Other diversional methods that may be used:

          • Ball sealers

          • Degradable particulate-diverting agents

          • Foam

          • Viscous fluids

TorF: An acid squeeze using a straddle packer assembly can only be performed on a well with a cased hole completion

False

• see the two videos in Student Resources (one for open hole and one for cased hole)

What is the purpose of having fresh water in the annulus of an injection well? Give 2 reasons.

Fresh water is placed in the annulus under pressure to provide a non‑corrosive, stable, easy‑to‑monitor barrier fluid that helps:

• protect the well (non-corrosive)

• maintain integrity and helps with early leak detection

  • pressure changes at surface would indicate a leak in the tubing, casing or packer

TorF: On injection wells, the annulus between the tubing and long‑string is often filled with a native produced brine or oil

False

• Per AER Directive 51, the annulus between the tubing and long‑string must be filled with a non‑corrosive fluid and kept under pressure.

  • Fresh water is often used for this purpose

Name 2 advantages of open-hole hydraulic fracturing using ball-drop activated sleeves

1. Open hole → No casing and cement required in lateral (saves $$)

2. Ball drop → Allows for continuous pumping

Name 3 advantages and 3 disadvantages of ball drop activated sliding sleeve MSHF systems

Advantages:

• Allows for continuous pumping

• No post-frac intervention required (ie. removal of plugs)

• Faster and simper than wireline plug and perf

Disadvantages:

• Lack of stage selectivity once installed

  • must frac toe to heel and can’t return to re-frac a stage

• Limited number of stages due to ball seat sizing constraints

• Ball seats remaining in hole present flow restriction unless milled out

Name 2 advantages and 3 disadvantages of plug and perf MSHF systems

Advantages:

Because there is no set sliding sleeve placement or set frac sequence, you can:

• Have complete freedom to choose your fracture initiation points

• React to real-time diagnostics and customize each stage as the frac progresses

Disadvantages:

• Requires multiple wireline/CT interventions

• Operational risks

  • perforating guns not firing,

  • wireline/CT failures,

  • fishing operations,

  • plug drill‑out complications.

• Higher operational time and cost vs. ball drop systems

Name 3 advantages and 3 disadvantages of CT activated MSHF systems

Advantages:

• High number of stages without seat‑size limitations

  • as in ball drop

• No post‑frac milling out of plugs required

  • as in plug and perf

• Immediate full-bore access

  • unlike ball drop, which has seat restrictions unless milled out

Disadvantages:

• CT operations face risks such as friction, lock‑up, and CT fatigue, especially in long horizontals.

• Slower stage‑to‑stage operations vs. ball‑drop systems

• Increased surface footprint/complexity and operational cost compared to ball‑drop systems

TorF: Spinner logs can be used to detect flow behind pipe

False

• Spinner logs are production logs that measure fluid velocity inside the wellbore

  • they need flowing fluid to spin the impeller

    • if the flow is behind the pipe it can’t spin the impeller

Name 3 logs that are used for wellbore integrity tests

1. Cement Bond Logs

2. Temperature Logs

   • detect flow channels behind pipe

3. Noise Logs

   • detect flow behind pipe

Note that temp and noise logs are typically run together. The temp log detects problem areas and the noise log is used to confirm flow in the area identified by the temp log.

Should an SCVF test be performed as part of a acid stimulation program?

• When?

• Why?

Yes - it should be performed after the acid stimulation job in order to confirm that there acid didn’t open up any channels in the cement to surface.

• could also be performed prior to the job in order to confirm wellbore integrity

Where is the packer set on an injection well?

As closely above the injection interval as practicable

AER Directive 051 references packer placement requirements in section 6.120 of the OGCR, which states:

6.120(1) Before any fluid other than potable water is injected to a subsurface formation through a well, the licensee shall:

• set a production packer in the well as closely above the injection interval as is practicable, and

• fill the space between the tubing and outer steel casing with a non-corrosive, corrosion inhibited liquid

How far below surface must casing be cut for abandonment?

According to the AER → minimum of 1m

According to Espo → should be 3m

What effect does iron have on an acid compatibility test?

The iron precipitates as ferric hydroxide

• This precipitated ferric hydroxide is an effective plugging agent, severely reducing permeability and damaging the formation

  • Studies show that iron precipitation can completely negate permeability gains from acidizing

Which term refers to a field‑based acid compatibility test performed on location?

a) Bottle test
b) Lab emulsion test
c) Shaker test
d) Acid titration test

c) Shaker test

Name 4 reasons that a packer would be used in an injection well

1. To isolate the injection zone

2. To protect the production casing from pressures/corrosive injection fluids

3. Allows the annulus to be pressurized and monitored separately from the injection tubing

   • This helps detect leaks, tubing failures, or casing integrity issues early

4. Helps support and stabilize the tubing string

   • Prevents downhole movement of the tubing caused by thermal expansion, injection pressures, or fluid forces

   • Helps manage axial loads on the tubing string and keep the system mechanically stable

What is the purpose of a step-rate injectivity test?

A step‑rate injectivity test is a diagnostic injection test that increases pump rate in controlled steps to determine the formation’s fracture pressure and establish the maximum safe injection pressure

Which of the following well classes require annual packer isolation tests?

a) 1a only

b) 1a and 1b

c) II, III and IV

d) 1a, 1b, II, III

d) 1a, 1b, II, III

Which well class has the most stringent monitoring requirements?

1a → used for disposal of high risk oilfield waste