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Formation Damage and Matrix Stimulation Core
Introduction
Why Take This Module?
It is a common occurrencefor an oil and gas operatororganization to bring on awell after initial drilling andcompletion or after aworkover and observe thatthe production rate is notas expected
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Why Take This Module?
If rates are greater thanexpected, there is someinterest and evaluation asto why and a study maycommence
Production Rates
Why Take This Module?
Not accurately identifyingthe correct causes of lessthan expected productionwill often lead to costlyremedial attempts that likelywill result in the failure toachieve a well’s maximumproductive capacity
Proper investigative studiesthat lead to identification oftrue formation damage willprovide the engineer withproven remediation tools toregain well productivity
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Why Take This Module?
If acidizing a formation ischosen as a remediationstep to take, the stimulationdesign engineer must alsounderstand corrosioncontrol, iron control, aciddiversion, etc., to achieveoptimum stimulation results
Acid Diverting Agents
Why Take This Module?
Poor corrosion control practicescan lead to catastrophic failureof well completions
Elemental iron is often presentthroughout a reservoir’slithology and ignoring theeffects of iron that goes intosolution during an acid jobto restore productivity can
readily turn a successfulacid job into a failure
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Why Take This Module?
If proper acid diversion techniquesare not properly analyzed anddesigned as a fundamentalcomponent of an acid job, theacid pumped may just reactthe most permeable portionsof the reservoir, thus leadingto job failure
Acid Diverting Agents
Why Take This Module?
The chemistry of limestoneand sandstone remedialacid job treatments torestore production differgreatly
Properly identifyingformation damage andapplying remedial actionswill provide the opportunityto restore a well to itsmaximum productivity
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Formation Damage and Matrix Stimulation Core
Formation Damage
Formation Damage
Matrix Stimulation
Module Contents
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Learning Objectives
By the end of this lesson, you will be able to:
Identify the basic causes of oilfield formation damage and how they are recognized
Outline the concept of “True Formation Damage” and the principles of formation remediation once it has been correctly identified as being the cause of lost production
Describe examples of “pseudo” formation damage and identify how it differs from True Formation Damage
This section will cover the following learning objectives:
Near Wellbore Formation Damage
near-wellbore area affected by unwanted
pressure drop “S” value
damage is concentrated radially near the wellbore
rw wellbore radius
re drainage radius
rd damaged zone
reservoir drainage area
h reservoir thickness
area x thickness =volume
is approximate
- ∆ Pskin
damaged zone
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Near Wellbore Formation Damage
Clean Sandstone Sandstone With Some Clay Content
Sandstone With Significant Clay Content
Formation damage is often assessed by reservoir engineering conducting a form of well test
• Build-up test• Fall off test • Multi-rate well test
Well Inflow Equation:
Stimulation Affects “S”:• Skin Factor, S
– Damage removal by acidizing will reduce the skin factor “S”
• Formation Capacity, kh– Formation can produce at its unrestricted “kh value” when skin is
removed
Near Wellbore Formation Damage – “Skin”
Qkh P Pres wf
rB ln r Sew 0Flow rate
Reservoirparameters
Pressuredrop
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Formation damage is often assessed by reservoir engineering conducting a form of well test
• Build-up test• Fall off test • Multi-rate well test
Well Inflow Equation:
Stimulation Affects “S”:• Skin Factor, S
– Damage removal by acidizing will reduce the skin factor “S”
• Formation Capacity, kh – Formation can produce at its unrestricted “kh value” when skin is
removed
Near Wellbore Formation Damage – “Skin”
Qkh P Pres wf
rB ln r Sew 0
If the well has a negative S, then the well has a higher than
expected flowing bottom hole pressure, indicating less
drawdown is required to produce the well at a given rate. This
would be a highly stimulated well.
If S is positive, then the well has a lower than expected flowing
bottom hole pressure, indicating more drawdown is required to
produce the well at a given rate. This would be damage.
Formation damage is often assessed by reservoir engineering conducting a form of well test
• Build-up test• Fall off test • Multi-rate well test
Well Inflow Equation:
Stimulation Affects “S”:• Skin Factor, S
– Damage removal by acidizing will reduce the skin factor “S”
• Formation Capacity, kh – Formation can produce at its unrestricted “kh value” when skin is
removed
Near Wellbore Formation Damage – “Skin”
Qkh P Pres wf
rB ln r Sew 0
If the well has a negative S, then the well has a higher than
expected flowing bottom hole pressure, indicating less
drawdown is required to produce the well at a given rate. This
would be a highly stimulated well.
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The term skin is actually a combination of many individual pressure changes.
Positive skin would be unwanted pressure drops.
Negative skin would be less pressure drop than expected.
There is more concern over unwanted pressure drops, as these can reduce production.
Skin Factor “S” Defined
Stotal =
Sdam Skin caused by true formation damage
+Sperf Skin caused by poor perforation charge / gun design
+Sturb Skin caused by non-laminar flow
+Sdev Skin caused by wellbore deviation
Skin Factor “S” Defined
h
Deviated Wellbore Through Zone
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Stotal =
Sdam Skin caused by true formation damage
+Sperf Skin caused by poor perforation charge / gun design
+Sturb Skin caused by non-laminar flow
+Sdev Skin caused by wellbore deviation
**Skin caused by gravel packs + Sgravel
**Skin caused by stimulation + Sstim
**Skin caused by frac jobs + Stemp
Skin caused by natural fracs + Sfrcs
** Skin by other causes + Sother
Skin Factor “S” Defined
** When these jobs are properly designed, skin will not result
Stotal =
Sdam Skin caused by true formation damage
+Sperf Skin caused by poor perforation charge / gun design
+Sturb Skin caused by non-laminar flow
+Sdev Skin caused by wellbore deviation
**Skin caused by gravel packs + Sgravel
**Skin caused by stimulation + Sstim
**Skin caused by frac jobs + Stemp
Skin caused by natural fracs + Sfrcs
** Skin by other causes + Sother
Skin Factor “S” Defined
** When these jobs are properly designed, skin will not result
* For example, skin caused by dirty fluid, Sdam is likely a result of True Formation Damage which consists of absolute permeability reduction, or “plugging” and relative permeability reduction, or “fluid related oil or water
wetting”, depending upon the type of dirty fluid; True Formation Damage may also be caused by fluid viscosity increase which is caused by emulsions
forming
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Near Wellbore Formation Damage
Altered Zones
Created by (altered by) Formation Damage
Improved (altered by) acidizing
h
XX
Skin Factor “S” Defined
Represents “dimensionless” near well bore pressure drop
Pressure drop caused by damage is typically near the well
“True Formation Damage” consists of:• Absolute permeability reduction – effects plugging the rock pore space• Relative permeability reduction – effects altering wettability of rock • Viscosity increase – effects caused by emulsions
pskin – This would be positive skin, showing a lower than expected flowing bottom hole pressureF
low
ing
Bot
tom
Hol
e P
ress
ure
(P
wf)
Distance from Well
Pwf expected
Pwf actual
Examples of True Formation Damage
- Any filtrate invasion- Any solids invasion- Oilfield scales- Waxes- Asphaltenes- Emulsions
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The clay occupies porethroats which would thenreduce the ability ofreservoir fluids to flowthrough those pore throats
For a given productionrate, Q, this rock wouldrequire a greater pressuredrop to overcome therestriction caused by theclays
That additional pressuredrop shows up as apositive skin in thedenominator of the usualinflow equation
Illite Clay Damage in Sandstone
Skin Factor “S” Defined
Pressure drop that is not “True Formation Damage” consists of:• Drilling related induced stresses in the rock• Formation compaction over time• Partially penetrating a zone• Deviated well through zone
Flo
win
g B
otto
m H
ole
Pre
ssur
e (
Pw
f)
Distance from Well
Pwf expected Pwf actual
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Skin Factor “S” Defined
Pressure drop that is “True Formation Damage”:• May be removed using proper stimulation techniques
Pskin
Flo
win
g B
otto
m H
ole
Pre
ssur
e (
Pw
f)
Distance from Well
Pwf expected
Pwf actual
Formation Damage Resolution
Acid Stimulation Treatment Gains
Acid matrix stimulation treatments achieve productivity increase results
Matrix stimulation refers to treatment of the formation below fracture pressure
• Matrix stimulation treatment selection process is critical
Fluid selection parameters important
Treatment design important
Operational procedures for matrix stimulation important
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Learning Objectives
By the end of this lesson, you will be able to:
Identify the basic causes of oilfield formation damage and how they are recognized
Outline the concept of “True Formation Damage” and the principles of formation remediation once it has been correctly identified as being the cause of lost production
Describe examples of “pseudo” formation damage and identify how it differs from True Formation Damage
This section has covered the following learning objectives:
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Formation Damage and Matrix Stimulation Core
Matrix Stimulation
Formation Damage
Matrix Stimulation
Module Contents
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Learning Objectives
By the end of this lesson, you will be able to:
Outline the principles of limestone matrix acidizing and thechemistry and reactions involved
Outline the principles of sandstone matrix acidizing and thechemistry and reactions involved
This section will cover the following learning objectives:
8 Years of Acid Stimulation Treatment Gains
Typical Results
0
4,000
8,000
12,000
16,000
20,000
Productivity Gains Due to Stimulation(m3/d oil equivalent)
Major Operator “A” 8 Year Historical Comparison Period
(25,160 bpd)
(50,320 bpd)
(75,480 bpd)
(100,640 bpd)
(125,800 bpd)
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Stimulation Treatment Gains Over 6 Years
350 Treatments: Average gain of 75 m3 oil/d/job (472 bpd)
Average Job Cost: $118,000
Total gain: 27,833 m3/d (175,060 bpd)
Total Expenditure: US$ 44,250,000 in year #6
Failure Rate: 20% (mainly matrix treatments)
US$ Invested / Additional BOPD ProductionUS$/bpd
0
100
200
300
400
Major Operator “B” - 6 Yr Historical Comparison Period
Acid “diversion” may improve treatment effectiveness
• Below the formation “fracture gradient”
Matrix Acid Stimulation Objectives
Treat the pore spaces in the formation near the well bore
Use acids to attack and chemically react and removedamage
Conduct job at pressures below that which would fracturezone
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Matrix acid treatment volumes are typically pumped at a plannedwell bore depth for acid penetration to be most effective
Lab core analyses with chemical treatment options and costs areevaluated
Chemical volume increases as a function of r2
% o
f P
rod
uct
ivit
y L
ost
Radial Extent of Damaged Zone (m)
Matrix Acid Stimulation Objectives
CriticalMatrixRegion
0
20
40
60
80
100
0 0.5 1 1.5 2 2.5 3
80% Damage90% Damage95% Damage98% Damage
Note: 55% of damage at approximately
0.65 m (2.1 ft) from well per lab analysis
(1.6 ft) (3.3 ft) (4.9 ft) (6.6 ft) (8.2 ft) (9.8 ft)
Matrix Stimulation Candidate Selection
Hydrocarbon Saturation 30% or more
Water Cut 40% or less
Gross Reservoir Height no limit
Permeability Gas > 1 mD, Oil > 20 mD
Reservoir Pressure Gas: 2 x abandonment pressure Oil: pressure at 80% depletion
Production System: Current production not more than 80% of maximum facilities capacity
Establish Appropriate Guidelines
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Matrix Stimulation Candidate Selection
Hydrocarbon Saturation 30% or more
Water Cut 40% or less
Gross Reservoir Height no limit
Permeability Gas > 1 mD, Oil > 20 mD
Reservoir Pressure Gas: 2 x abandonment pressure Oil: pressure at 80% depletion
Production System: Current production not more than 80% of maximum facilities capacity
Establish Appropriate Guidelines
WILL WILL NOT
Increase the average reservoir pressure
Create more hydrocarbon saturation in the pore space
Improve the rate of production of the reservoir fluids
Improve the production of water
Matrix Stimulation Candidate Selection
GUIDING PRINCIPLES
Start with the best available information for well data, decision criteria, assumptions, and expectations
Conduct involved analyses on candidates
Rank candidates on all combinations of properties (local circumstances, risk, etc.)
Evaluate the organized hierarchy (group, operating unit, field specific, etc.) from past experience
Apply system “learning” through feedback to check defaults (post job analysis)
Avoid the tendency to choose poor candidates with the intent to turn poor ones into great ones
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Stimulation Planning
Stimulation Treatment Process
Treatment Design
Site Preparation
Evaluation Cycle
Operational Stimulation
Program
Schedulingand
Logistics
Treatment ResultPrediction
Treatment Selection
Problem Classification
Problem Well Identification
Diversion, Additives,Other, etc.
Operational Constraints
Job Execution
Types of Treatment Chemicals to Treat Damage Causes
CAUSE OF DAMAGE
*Stim Damage, Gravel Packing, Perforating, etc.
Drilling, Completion,
etc.
Chemical Interaction
Wax, Asphaltenes
Mud Acid Treatment
Solvent / Surfactant Treatment
Acid Treatment
Produced Fluids
Formation Fines
Precipitates, Clay Swelling
Emulsions
Solvent / Surfactant Treatment
Acid Treatment
Injected Fluids
Water
Precipitates, Scale
Clay Swelling Mud Acid Treatment
Oily / Inhibitor Residues
Solvent / Surfactant Treatment
Specific Well Treatment*
(Mud) Acid Treatment
LIM
ES
TO
NE
O
R
SA
ND
ST
ON
E
Gas
TYPE OF TREATMENTDAMAGE TYPESolids
Invasion
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Work Closely with Chosen Service Company
Work Closely with Chosen Service Company
Perform Laboratory Tests• This is most important to be able to determine the correct and
appropriate treatment method
Purpose• Identify and quantify damage type• Evaluate suitable removal treatment options• Decide upon key treatment design parameters• Assess necessity / application of additives, solvents, etc.• Conduct various lab evaluations
– Fluid compatibility tests– Core flow tests
– Corrosion tests
– Emulsion tests– Reaction rate measurements
– Rock mechanical properties
• Propose/write a program to perform a remedial activity on the well
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Various Treatment Designs
Matrix acidizing of sandstones• Complex HCl-HF acid
3 stage pumping schedule
• Water wet rock conditions must be retained
Solvent treatments
Matrix treatments of limestones• Normally, HCl acid
used due to its reacting power and low cost
Treatments with surfactants, specialty treatments, etc.
Sandstone Stimulation
For sandstone rock reservoirs• HF acid reacts and removes damaging clays
In any acid job, corrosion is a primary concern• Corrosion inhibitors protect well tubulars and equipment
• For a sandstone reservoir, hydrofluoric acid is used
• The acid is blended and is toxic
• Blending it with hydrochloric acid allows sandstones to be properly treated
Hydrochloric Acid / Hydrofluoric Matrix Acid Sandstone Job
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Stage #3 Post Flush Mutual solvent and surfactant return rock to the preferred
“water wet” state
Summary – Mechanism of Sandstone “Mud Acid” Job
Stage #1 Pre Flush Reacts carbonates Displaces formation water away from zone being acidized
Stage #2 Main Flush (mineral dissolution is by reactivity) Reacts clays – very reactive with HF Reacts feldspars – reactive with HF Reacts silica – slowly reactive with HF
SiO2 + 4HF SiF4 + 2H2OSiF4 + 2HF H2SiF6
CaCO3 + 2 HF CaF2 + CO2 + H2O
Al2Si2O5(OH)4 + 18HF 2H2SiF6 + 2AlF3 + 9H2O
NaAlSi3O8 + 22HF 3H2SiF6 + AlF3 + NaF + 8H2O
HCl/HF “Mud Acid” Stage #2 Reactions
Mud acid treatment reaction with feldspar
Mud acid treatment reaction with clay (kaolinite)
Mud acid treatment reaction with carbonate (calcite)
Mud acid treatment reactions with silica (quartz)
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HCl Matrix Acid Job Basics
Limestone Stimulation
For carbonate rock reservoirs• HCl reacts and removes the rock matrix • Damage in the rock matrix is flowed away with the reaction
products
In any acid job, corrosion is a primary concern• Corrosion inhibitors protect well tubulars and equipment
HCl Acid Stimulation
Acid Reaction on Carbonate Reservoir• Dissolves the matrix and thus removes damage • Reaction is: (much simpler compared to sandstone reactions)
2HCl + CaCO3 CaCl2 + CO2 + H2O
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2 HCl + CaCO3 CaCl2 + CO2 + H2O
Hydrochloric Acid / Limestone Reaction Products
The above reaction is immediate, total, and linear.
That is, 50% increase in 15% HCl volume would react a 50% increase in limestone volume to create a 50% increase in reaction products.
1000 gallons 15% HCl
1840 lbs CaCO3 (10.5 ft3)
7600 lbs water (3447 kg)
1350 lbs HCl (612 kg)
2050 lbs CaCl2 [68 gals (2.6 m3)]
812 lbs CO2 [6600 ft3 (187 m3)]
333 lbs H2O [40 gals (.15 m3)]
(3.8 m3)
(835 kg) (.3 m3)(930 kg)
(368 kg)
(151 kg)
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Acid Corrosion Inhibitors
ALL acid jobs require an acid inhibitor
Protect tubulars from acid corrosion
Protect downhole equipment
Protect surface treating equipment
Importance of Inhibitor Program Design
Check to assure that the inhibitor layer is thoroughly mixed into the acid volume for all acid jobs
Mechanical setup to assurethat mixing occurs
Pump
Inhibitorproperly
recycled with acid
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Acid Diverting Agents Used
Ideal acid injection patternwith acid uniformly enteringradial matrix
Normally does not happenwith uniform aciddistribution
Diverting agents function byselectively reducing the flowof acid into the morepermeable portions of theproducing zone
rWH
req
rw
Acid “Wormhole” Effect – Lab Core Tests
2% SGA-II Only All VCA AdditivesCastings From Hollow Core Tests 141°F (60.6°C), 5% HCl, 10 ml/min
Lab tests clearly illustrate that acid seeks high perm streaks
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HighPermeable
Zone
Various Acid Diversion Techniques
SelectivePlacement
Tool
Ball Sealers Viscous Pill
PerforationBlocked WithBenzoic Acid
PerforationBlocked With
Foam
ZoneBlocked
WithViscous Gel
Ball Sealers Type of Acid Diverting Agent
Ball Sealers Features• Effectively Seal on Perforations• Achieve Positive Shut-off• Non-Damaging• Easy to Use• Independent of Formation
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Other Damage Treatment Designs
Matrix acidizing of sandstones• Complex HCl-HF acid
3 stage pumping schedule
• Water wet rockconditions must be retained
Solvent treatments
Matrix treatments of limestones• Normally, HCl acid
used due to its reacting power and low cost
Treatments with surfactants, specialty treatments, etc.
Damage Problem / Solvent Treatment Selection Chart
Aromatic Solvent
Kerosene/Diesel
AlcoholicSolvent
MutualSolvent
Wax
Asphaltene
Emulsions
Scale/SludgeWaterBlock
Legend: Reasonable Poor Preferred
Problem Surfactant
Pipe Dope
Oil BasedMud
Paint, etc.
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Common Commercially Available Solvents
Brand Name Chemical Class Manufacturer Claims
Musol EGMBE Halliburton
Musol A EGMBE derivative Schlumberger Dowell
Improved action
U-66 EGMBE BJ
J-40 EGMBE BJ?
WSA-1 EGMBE (?) BJ?
Cellosolve EBMBE BJ?
A-sol series Alcoholic mixtures Petrolite Better than EGMBE in most applications
MAS Micellar Solvent BJ? Prevents emulsions
EGMBE = Ethylene Glycol Mono Butyl Ether
Oilfield Scale Damage Remediation Selection
HCl Converter+ HCl
ChelatingAgents Skinfrac
Carbonates
IronCompounds
CalciumSulphateBarium
SulphateMixedScales
Legend Preferred
Reasonable
Poor
Problem
Soluble or Insoluble
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Matrix Stimulation Job Control
Well site job control is, in principle, the responsibility of thestimulation contractor
Pre-treatment safety meeting by contractor and siterepresentative
• To be attended by all staff on location
Safety Aspects• All activities, emergency plans, safe working practices etc.
Operational Aspects• Discussion of the plan and individual roles
HSE Issues• Disposal plans for produced fluids, empty drums, etc.
Learning Objectives
Outline the principles of limestone matrix acidizing and thechemistry and reactions involved
Outline the principles of sandstone matrix acidizing and thechemistry and reactions involved
This section has covered the following learning objectives:
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Back to Work Suggestions
Drilling Fluids and Solids Control Core
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Meet with a reservoir engineer to review well data that indicates skin damage that has been identified based upon build up or fall off pressure tests.
Review well history files to attempt to determine the potential source or causes of the skin damage identified above. Consider damage causes related to activities such as: drilling, completion, workover, intervention, stimulation, or other treatment related causes when reviewing the referenced files.
Back to Work Suggestions
Drilling Fluids and Solids Control Core
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Meet with a production engineer and review well stimulation programs previously performed on your wells. Also review post stimulation job results that indicate production improvement as well as limited or minimal production improvement.
Meet with a geologist to review the differing formation mineralogy components present if your reservoirs are sandstones. If your organization’s production comes primarily from limestone formations, have the geologist illustrate the matrix porosity reservoir model or dominant fracture porosity reservoir model that contributes to providing most, or the greater proportion, of overall production.
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Back to Work Suggestions
Drilling Fluids and Solids Control Core
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Work with operations engineers to review if and how diverting agents are a regular and important component of acid jobs performed in your wells.
Work with operations engineers to determine how diverse your well stimulation problems are to address issues such as paraffins, asphaltenes, oilfield scales, and other downhole factors affecting production and requiring attention and treatment.
Visit with a service company representative and review the detailed, multi‐step programs and production chemistry recommended to improve overall well performance.
PetroAcademyTM Production Operations
Production Principles Core Well Performance and Nodal Analysis Fundamentals Onshore Conventional Well Completion Core Onshore Unconventional Well Completion Core Primary and Remedial Cementing Core Perforating Core Rod, PCP, Jet Pump and Plunger Lift Core Reciprocating Rod Pump Fundamentals Gas Lift and ESP Pump Core Gas Lift Fundamentals ESP Fundamentals Formation Damage and Matrix Stimulation Core Formation Damage and Matrix Acidizing Fundamentals Flow Assurance and Production Chemistry Core Sand Control Core Sand Control Fundamentals Hydraulic Fracturing Core Production Problem Diagnosis Core Production Logging Core Production Logging Fundamentals
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