Showing posts with label Stimulation. Show all posts

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

Oil well Stimulation con't 1

Vertical and horizontal fractures

Vertical fracture occurs in deep reservoirs when fracture gradient is less than overburden gradient

Horizontal fracture occurs in shallow reservoirs

Fracture occurs n a direction vertical to the smallest principal stress i.e. the minimum work

Two basic methods of hydraulic fracturing

1-Proppant fracturing

Proppant fracturing requires that small particles be pumped with the fluid into the fracture. An effort is made to pack the fracture with a bed of these particles in order to support the walls of the fracture to form a conductive path to the wellbore.

PROPPANT FRACTURING

The objective of proppant fracturing: is to pack the dynamic fracture with proppant (small particles) so that when the fracture treatment has terminated and production commences, the fracture will remain conductive. The need to pack the fracture with some form of propping agent was recognized early in the development of the process.

Production from fractured wells not propped declined rapidly.

One of the important design considerations will be to select a fluid capable of transporting and holding the proppant particles in suspension until the fracture has closed.

Proppant Types:

· Sand.

· Sintered bauxite

· Ceramics.

1-Sand

Sand has proven to be successful as a proppant for all types of reservoirs, and it is less expensive than other types of proppant.

Sand for use as proppant should not contain more than 5 wt% fines which, if present in excessive quantities, reduce the fracture conductivity.

Advantage:

When crushed, it breaks into smaller fragments, rather than being powdered. This particular advantage helps to maintain high fracture conductivities even when the closure stresses supported by the proppant are large

2-Sintered bauxite

A high-strength proppant (compressive strength in excess of 1 x 10⁵ kPa), which does not crush as readily as sand under high closure stresses.

Bauxite is denser (p_p - 3400-3800 kg'm³) than sand (2650 kg/m³

The fracture fluid designed to transport bauxite will have to be more viscous and hence more expensive than a fluid that will transport sand.

3-Ceramics

Other high-strength proppants have been developed which appear to have advantages with respect to sintered bauxite: however, these are not yet widely applied.

Propped Fracture Conductivity

FC = w_fk_f

Wf is the final average fracture width

K_f permeability of proppant-packed fracture

FC has the dimensions of length cubed; it may be reported as darcy-fcet, darcy-inches, or even millidarcy-feet.

Fracture permeability.

Final fracture permeability is strictly a function of the diameter of the proppant particles used in the treatment. According to the Blake-Kozeny equation

d_p is the diameter of the proppant particle

is the porosity of the packed, multilayer bed of proppant particles.

The fracture permeability increases with the square of the proppant particle diameter.

Therefore, it is desirable to use large proppant particles. Actually, the size of the proppant is an optimization problem that must always be settled on economic grounds. Larger particles will require more expensive fluids to transport them. The optimum will depend on a large number of factors, all of which will be discussed later.

Fracture width.

The final fracture width is strictly related to the concentration of proppant in the fracture when it closes.
For a well-designed fracture fluid, proppant settling is minimal.

is the average dynamic fracture width at the end of pumping

mi is the mass of proppant per unit volume of fluid

is the density of proppant

is the mass of proppant per total volume, including both proppant and fluid.

The effect of closure stresses.
The fracture conductivity can be calculated by the multiple of wf times kf.
This calculated conductivity will exceed the field value when the closure stresses exerted by the overburden become large. In this case, the proppant will embed into the formation causing the actual fracture width to be less than that calculated and also proppant crushing may cause the effective proppant radius to be reduced, thereby reducing the permeability of the fracture.
Closure stress = PBISIP - Pwf by maintaining the bottomhole welt flowing pressure at a high level, part of the overburden stresses can be supported by the fluid in the fracture. Generally, however, to produce the well at an economic rate, pwf is much less than the reservoir pressure (large drawdown) and the proppant must support nearly the entire overburden.

Graph showing the permeability of a propped fracture as a function of the closure stress.

Proppant Settling Velocities
The selection of a fluid is one of the critical steps in the design of a fracture treatment. One of the important properties required of the fluid is an ability to transport and hold the proppant in suspension. It is important to be able to calculate the rate at which particles settle under the influence of gravity.
Two different types of fluids will be considered here
1- Non-Newtonian polymer solutions

2- Foams

1-Non-Newtonian fluids
When a particle settles in a fluid under the influence of gravity, it reaches a constant velocity so that the frictional forces are in balance with the gravitational forces. For Reynold's numbers less than about 2, that is, for

The settling velocity (vs)

The apparent viscosity depends on shear rate and is therefore not a constant. Slattery and Bird have shown that for particles settling in a quiescent non-Newtonian fluid.

2-Foams
The settling of proppant particles in foams must be a complex function of the wettability of the particles, the quality of the foam, and its stability.
No general theory has been presented which shows the relationship of these factors.

Design and optimization of fracture processes
The final design will be best in some economic sense and requires different considerations:

1-Proppant fracture
   1-Selection of fracture fluid and additives
   2-Design of proppant fracturing treatments
   3-Practical considerations in designing fracture
2-Selection of fracture fluid and additives fluid properties:
   1-Low fluid loss
   2-Ability to carry and suspend the proppant
   3-Low friction loss
   4-Easy to recover from the formation
   5-Compatible with formation fluids and nondamaging
   6-Reasonable cost

Oil well Stimulation con't 2

Oil well Stimulation con't

Hydraulic fracturing

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hydraulic fracturing
has been and will remain, one of the primary engineering tools for improving well productivity. This is achieved by
placing a conductive channel through near wellbore

damage, bypassing this crucial zone

extending the channel to a significant depth into
the reservoir to further increase productivity
placing the channel such that fluid flow in the reservoir is altered

Proper treatment design is thus tied to several disciplines
production engineering
rock mechanics
fluid mechanics
selection of optimum materials
operations.

what is fracturing

If fluid is pumped into a well faster than the fluid
can escape into the formation , inevitably pressure rises,
and at some point something breaks.

Injecting fluid into formation at pressure higher than the fracturing pressure of the formation creates fractures which propagate as more fluid is injected

Methods of hydraulic fractures
Acid fracturing
Proppant fracturing

Basic reasons for hydraulic fracturing

1- increase the rate or productivity

2- improve ultimate recovery

Fracture orientation

Fracture either horizontal or vertical
pressure behavior for fracturing formation
break down pressure: the pressure required to break the formation and initiate fracture.
Propagation pressure: the pressure required to continually enlarge the fracture.
Instantaneous shut in pressure: the pressure required to hold the fracture opened.

Idealized pressure behavior during fracturing

Oil well Stimulation con't 1

Oil well Stimulation con't 2

Oil well Stimulation

Oil well stimulation plays a vital role in production operations. With oil prices at all-time highs, it is imperative from an oil company's perspective and the consumer's perspective that as much production as possible be safely extracted from the reservior .

why do wells need oil well stimulation?
Hydraulic fracturing and acid fracturing in practically all types of formations and oil gravities, when done correctly, have been shown to increase well productivity above that projected in both new and old wells. From an economic standpoint, oil produced today is more valuable than oil produced in the future. Fracturing candidates may not necessarily "need" oil well stimulation, but the economics may show that such a treatment would pay=off.
To understand why remedial stimulation (matrix acidization) is necessary, you have to consider the conditions at work, deep down inside the reservoir...
Before the well is ever drilled, the untapped hydrocarbons sit in the uppermost portions of the reservoir (atop any present water) inside the tiny pore spaces, and in equilibrium at pressures and temperatures considerably different from surface conditions.
Once penetrated by a well, the original equilibrium condition (pressure, temperature, and chemistry) is permanently changed with the introduction of water or oil-based drilling fluids loaded with suspended clays, and the circulation of cement slurries. The interaction of the introduced fluids with those originally present within the reservoir, coupled with pressure and temperature changes can cause a variety of effects which, in turn, can plug the numerous odd-shaped pores causing formation damage. Some of the types of damage include: scale formation, clay swelling, fines migration, and organic deposition.
Petroleum engineers refer to the level of formation damage around the wellbore as skin effect. A numerical value is used to relate the level of formation damage. A positive skin factor reflects damage/impedance to normal well productivity, while a negative value reflects productivity enhancement.
Formation damage, however, is not limited to initial production operations. Remedial operations of all kinds from well killing to well stimulation itself, can cause formation damage. Nor is fines and scale generation limited to the reservoir. They can also develop in the wellbore in casing and tubulars, and be introduced from surface flowlines and incompatible injection fluids. These fines and precipitates can plug pores and pipe throughout an entire oil field.
In short, any operation throughout a well's life can cause formation damage and impede productivity.
types of Stimulation:-
1- Hydraulic fracturing
2- Acid fracturing

to be con't

Oil well Stimulation con't

Oil well Stimulation con't 1

Oil well Stimulation con't 2

Microseismic Hydraulic Fracture Monitoring

StimMAP services for hydraulic fracturing monitoring record microseismic activity in real time during the fracturing process. A full range of software provides modeling, survey design, microseismic detection and location, uncertainty analysis, data integration, and visualization for interpretation, wherever and whenever decisions must be made. Computer imagery is used to monitor the activity in 3D space relative to the location of the fracturing treatment. Then the monitored activities are animated to show progressive fracture growth and the subsurface response to pumping variations.

The StimMAP service uses Petrel seismic-to-simulation software to provide accurate characterization of the locations, geometry, and dimensions of a hydraulic fracture system. Advanced processing techniques provide fracture characterization that enhances fracture models and reservoir characterization for production simulation.

Microseismic monitoring, which delivers information about the changing stress of a reservoir can be used to enhance reservoir development in tight gas completions, fault mapping, reservoir imaging, waterflood monitoring, drilling waste disposal, and thermal recovery.

StimMAP LIVE Microseismic Fracture Monitoring Service

StimMAP LIVE microseismic fracture monitoring in real time provides fracture monitoring within 30 seconds of microseismic activity. Based on proprietary coalescence microseismic mapping (CMM) that allows processing more events per minute than would be possible with hand picking, there is close agreement for the fracture geometry on the same dataset. The CMM technique provides more events because multiple arrivals can be handled in a single time window.

Accurate fracture characterization

Understanding fracture geometry is key to effective stimulation treatments and well economics. Microseismic fracture monitoring provides imaging of the geometry of a hydraulic fracture to accurately measure fracture geometry. Accurately measuring the fracture geometry offers precise data on hydraulic fracture systems to increase understanding of the fracturing process. This increased understanding in real time

reduces well stimulation costs
optimizes field drilling plans
allows changes in perforation strategies and plan diversion schemes to be made on the fly.

Treatment Execution

Treatment Execution

Schlumberger develops innovative methods and provides the right equipment to perform stimulation treatments in any environment.
Candidate Recognition

Analyzing client data is critical in determining the economic viability of oil and gas reservoirs.
Monitoring Stimulation Treatments

Accurate characterization of the locations, geometry, and dimensions of a hydraulic fracture system makes optimization of reservoir performance possible.
Fracturing Computer-Aided Treatment | InterACT for Stimulation Operations
Offshore vessels

BIGORANGE XVIII Stimulation Vessel | DeepSTIM Stimulation Vessel | DeepSTIM Pronto Offshore Stimulation Equipment | FlexSTIM Offshore Stimulation System
Well Optimization Service

Customize stimulation treatment design and execution to specific reservoir conditions.

Candidate Recognition

Better Wells

Candidate recognition is a key element in improving the economics for producing oil and gas. The process begins with Schlumberger engineers gathering and organizing well data. Then a NODAL systems analysis is performed to determine if the well is producing at or near maximum potential. Specific factors restricting production and their location are determined and wells with the potential for enhanced production from a stimulation treatment are identified.

After the assessment, the overall field is mapped to show the geographic relationship of the wells, their production potentials, and other selected parameters. After identification of the candidates, the Schlumberger engineer develops detailed stimulation treatments.

The DESC Design and Evaluation Services for Clients, where a Schlumberger engineer and the complete range of software and hardware are placed in the client's office, helps in the candidate recognition process.

Monitoring Stimulation Treatments

Accurate characterization of the locations, geometry, and dimensions of a hydraulic fracture system makes optimization of reservoir performance possible.

FracCAT Fracturing Computer-Aided Treatment

Monitor, Record & Control Stimulation Treatments in Real Time

The FracCAT fracturing computer-aided treatment system comprises hardware and software for monitoring, controlling, recording and reporting all types of fracturing treatments. Its real-time displays, plots, surface schematics and wellbore animations present a clear picture of the treatment as it occurs, providing decision-makers with real-time detailed job information from the surface to the perforations.

Technology and software

Using FracCAT technology, treatment design is followed and execution is precise. Integration with the Schlumberger FracCADE design and evaluation software allows job designs to be loaded directly into the FracCAT software.

During the job, the FracCAT system tracks the design and displays actual job parameters compared to planned values. FracCAT software also uses the design to control proppant and additive concentrations in as many as three blenders at the same time. This control capability ensures that actual concentrations follow the plan. Job data are sent to the FracCADE software in real time. If the FracCADE analysis indicates a need for design changes, the changes can be imported directly into the FracCAT software without interrupting the treatment. The FracCAT system works in conjunction with a local area network (LAN) environment, which enables networking of all PCs at the wellsite and also provides a connection to the Internet through satellite or cellular telephone technology. The Internet connectivity provides the ability to transmit real-time data from the remote wellsite to anywhere in the world for real-time analysis.

FracCAT controls make deviations from the schedule, such as extending a proppant stage or starting flush early, as simple as a single mouse-click.

Hardware

FracCAT hardware includes the latest high-performance PC systems. Innovations such as space-saving flat-panel displays and multiple monitors provide best-in-class presentation of data. All these features inside an ergonomically designed control cabin offer the ultimate job control environment and make the FracCAT system the premier tool for fracturing treatments.

Offshore vessels

We bring stimulation services to the world's high seas. BIGORANGE XVIII is purpose-built for environmentally safe North Sea operations. Rapidly deployed DeepSTIM vessels in the Gulf of Mexico are reliable in severe weather, remaining offshore for long periods. Galaxie is an advanced, versatile well stimulation vessel.
BIGORANGE XVIII Stimulation Vessel

Purpose-built stimulation vessel designed for North Sea operations.
DeepSTIM Stimulation Vessel

Advanced, versatile stimulation fleet equipped with dynamic positioning systems.
DeepSTIM Pronto Offshore Stimulation Equipment

Modular, portable, flexible system designed for offshore supply vessels.
FlexSTIM Offshore Stimulation System

Flexible, high-capacity, rapid stimulation system.

PowerSTIM Well Optimization Service

Maximize Production with Enhanced Reservoir Characterization

PowerSTIM well optimization service gives you fit-for-purpose, solution-oriented technology that is effective in a broad range of reservoirs. We customize stimulation treatment design and execution to the specific conditions in your well or field, based on detailed, accurate formation evaluation and modeling.

Based on our analysis, treatment options, such as acid treatments, fracture treatments, or sand management, are considered. The knowledge gained from each stimulation treatment is used to improve the next job in a continuous, closed-loop process that reduces costs, maximizes production, and increases recovery.

A multidisciplinary team

The first step in the PowerSTIM process is forming the team of geoscientists, reservoir and production engineers, and stimulation designers. Initially, the team concentrates on a small group of wells, typically three to five, depending on field and reservoir complexity.

After collecting and analyzing all available data, the team builds a customized model that describes geology and reservoir dynamics. This model, which accurately predicts key parameters and forecasts production, is used to design optimized treatments for the first group of wells.

After these treatments are executed according to the design, the team evaluates the results and uses them to update the model, important information to optimize the next group of completions. The updated model often is available to decision makers within a few hours after the evaluation is finished.

A better approach

The PowerSTIM informed decision report or IDR an "in-time" report, documents the solutions with a complete, historical record for each well treated. InterACT real-time monitoring and data delivery improves collaboration, allowing you to keep an eye on the treatments as they occur.

Unconventional Gas Stimulation

Unconventional Gas Stimulation

Better reservoir knowledge and increasingly sensitive technologies are making production of unconventional gas economically viable and more efficient. This efficiency is bringing tight gas, coalbed methane, and gas hydrates into the reach of more companies around the world.
Microseismic Hydraulic Fracture Monitoring

Directly measure hydraulic fracture geometry.
Shale Gas Dynamic Fluid Diversion Service

Combine fluid-based, tool-free fracture diversion technology with real-time microseismic monitoring.
Staged Fracturing and Completion Services

Maximize reservoir contact with the most efficient and effective services for each well.

Conventional Sandstone Stimulation con't

Scale Control
Remove and Control Scale Buildup

Scale control challenges are the leading cause of declining production worldwide. They cost the petroleum industry millions of dollars each year in scale control and removal costs and in deferred production. Scale control through chemical inhibition is preferred for maintaining well productivity, but when scale forms on the wellbore, more advanced scale control techniques must be applied.

Schlumberger scale control services are not only effective at removing scale and preventing repricipitation, they are quick and nondamaging to the wellbore, tubing, or formation environment.
Jet Blaster Scale Removal
Polymer-Free Fracturing Fluids

The Schlumberger ClearFRAC family of polymer-free fracturing fluids enables a larger effective fracture half-length. The ClearFRAC fluid system also reduces friction pressure, allowing operators to save costs with reduced pumping equipment. Viscosity remains constant at a given temperature until contacted by formation fluids or added chemical breakers.

Applications include

* nitrogen and carbon dioxide (CO2) foam fracturing
* stimulation in hard-to-reach zones
* offshore operations.

The three ClearFRAC formulations each have specific applications.
CO2 Polymer-Free Fracturing Fluid

Significantly reduce operations costs with nitrogen foam fracturing treatments.
Polymer-Free Fracturing Fluid

Maximize conductivity with polymer-free fracturing.
High-Permeability, Polymer-Free Fracturing Fluid

Enhance fracture efficiency using the innovative viscoelastic surfactant (VES) system for low friction pressure and excellent proppant-carrying capacity.
Gelled-Oil Fracturing Fluid

YF GO III continuous-mix, gelled oil service

YF GO III is a patented gelled, oil-base sandstone fluid designed primarily for treating water-sensitive formations. Originally designed for continuous-mix operations, it is used successfully in both continuous and batch-mix conditions. YF GO III can gel diesel, condensates, and a wide variety of crudes as the oil base.
YF GO IV high-temperature, gelled-oil service

YF GO IV gelled-oil sandstone fluids are designed for broad use in sandstone applications where gelled oil is commonly used (i.e., water-sensitive formations). Originally designed for use only with clean, dry diesel, YF GO IV can be used with many dry, uncontaminated crude oils. The advantages of using YF GO IV include high-temperature stability, low static viscosity, and predictable rheological profiles.
HiWAY Channel Fracturing

How it works

To allow more fracture conductivity in conventional fracturing jobs, HiWAY channel fracturing fundamentally changes the way that proppant fractures generate conductivity. It engineers stable flow channels into the proppant pack that are connected from the tip of the fracture back toward the wellbore, creating the optimal connection between the reservoir and the wellbore. The productivity of the fracture is decoupled from the actual permeability of the proppant used, so rather than flowing through the proppant in the pack, hydrocarbons flow through stable channels—meaning infinite fracture conductivity.

Traditional losses in proppant pack conductivity from crushing, fines, fluid damage, multiphase flow, and non-Darcy effects are eliminated, ensuring more fluid and polymer recovery, meaning optimized production.
What it combines

A unique combination of placement and materials engineering, completions techniques, and process control equipment enables the success of HiWAY channel fracturing. The stability of the flow channels is ensured by using a proprietary fiber, which maintains the structures from surface to reservoir until the fracture has closed and the in situ stress of the rock takes over.
Where it’s used

HiWAY channel fracturing provides more fracture conductivity and optimized production for conventional consolidated rock fracturing treatments of oil and gas wells. For example, it has been successfully applied in the Rocky Mountain region of the US and the Sierras Blancas formation in Argentina for major improvements in time to sales, fluid recovery, initial production rate, and average-well estimated ultimate recovery (EUR).
Organic Clay Acid Stimulation Fluid
High-Performance Formation Cleanup Treatment

Wells in the sandstone formations common to the U.S. Gulf Coast generally have migrating fines that can plug the near-wellbore area and severely limit production. Although conventional stimulation fluids,such as hydrochloric (HCl) or mud acid, can clean up the wellbore and stimulate the sandstone, they do not penetrate deep into the formation nor stabilize fines. Conventional acids can also have adverse effects in formations with certain types of clays, like zeolite and chlorite, that are unstable in HCl acid.

OCA organic clay acid stimulation fluid penetrates deep into the sensitive formation and stabilizes clays and fines without the adverse effects of conventional acid systems.
Innovative acid system

OCA fluid is a high-performance acid system designed for sensitive sandstone sandstone formations that can present the biggest challenge to conventional acidizing treatments. Because of the damaging precipitation of secondary and tertiary reaction products, conventional mud acid has the highest chance of failure in formations with very high temperature or a high clay content that is sensitive to HCl.

OCA fluid combines a retardation effect and advanced chelation technology for stimulation deep into the reservoir with minimal precipitation. It reduces the risk of diminished production as well as secondary and tertiary mineral precipitation that can block pores. Its retarded properties allow a reduced corrosivity. OCA fluid also combats sludging problems that plague conventional acid systems and stabilizes formation fines while maintaining the integrity of the sandstone structures to promote long-term production.
Laboratory testing

Sequential spending tests that simulate deep formation penetration have demonstrated that the reaction between sandstone minerals and conventional acid systems can cause silica gel precipitation.

With conventional acids, silicon can deplete in a spent acid solution as it penetrates deep into the formation. In laboratory tests, the ratio of silicon to aluminum decreases as the acid penetrates deeper into the formation. This decrease indicates the precipitation of formation-damaging hydrated silica gel.

As OCA fluid penetrates deep into the formation, tests show increasingly higher silicon and aluminum concentrations. OCA fluid keeps all the dissolved ions in solution. The OCA fluid continues to dissolve without forming damaging secondary and tertiary hydrated silica precipitation.

Jetting scale removal service for effective one-trip wellbore cleaning.
ScaleFRAC Scale Inhibitor

Scale inhibitor service that protects wellbores and propped fractures from scale damage and related production declines.
ScaleMAT Acid-Compatible Scale Inhibitor

Acid-compatible scale inhibitor that enables scale inhibition at the same time as matrix stimulation.
ScalePROP Scale Inhibitor Proppant

Scale-inhibitor-impregnated proppant for long-term protection for fracturing proppant packs.
ScaleSOLV Carbonate Scale Dissolver

Carbonate scale dissolver to remove scale chemically without corrosion.

Monitoring Stimulation Treatments

Accurate characterization of the locations, geometry, and dimensions of a hydraulic fracture system makes optimization of reservoir performance possible.

FracCAT Fracturing Computer-Aided Treatment

Monitor, Record & Control Stimulation Treatments in Real Time

Technology and software

FracCAT controls make deviations from the schedule, such as extending a proppant stage or starting flush early, as simple as a single mouse-click.

Hardware

Conventional Sandstone Stimulation

Conventional Sandstone Stimulation

Matrix stimulation and hydraulic fracturing techniques are designed to repair and improve the natural connection of the wellbore with the reservoir.
Scale Control

Remove and prevent scale within wellbores and the reservoir.
Jet Blaster Scale Removal | ScaleFRAC Scale Inhibitor | ScaleMAT Acid-Compatible Scale Inhibitor | ScalePROP Scale Inhibitor Proppant | ScaleSOLV Carbonate Scale Dissolver
Polymer-Free Fracturing Fluids

Achieve a larger effective fracture half-length with ClearFRAC polymer-free fluids.
CO2 Polymer-Free Fracturing Fluid | Polymer-Free Fracturing Fluid | High-Permeability, Polymer-Free Fracturing Fluid
Gelled-Oil Fracturing Fluid

Use water-free, oil-base fluid for fracturing treatments in water-sensitive formations.
HiWAY Channel Fracturing

Experience more fracture conductivity by removing the link between fracture flow and proppant conductivity.
Organic Clay Acid Stimulation Fluid

Penetrate deep into sensitive sandstone matrix formations.
Matrix Acidizing Diverter

Direct treating fluids away from high-water-cut intervals.
High-Water-Cut Acidizing Diverter

Reduce water cut and increase production with an advanced acid diverter.
Simplified Sandstone Acidizing System

Stimulate sandstone reservoirs with a single fluid-stage formulation.
Proppant Flowback Control

Prevent flowback from hydraulic fractures.

Proppant Distribution

Create a fiber-based network within the fracturing fluid.
Microseismic Hydraulic Fracture Monitoring

Measure hydraulic fracture geometry in real time.
Staged Fracturing and Completion Services

Maximize reservoir contact by offering the most efficient and effective services for each well.

Carbonate

Carbonate Reservoir Stimulation

Understanding and addressing the specific challenges and technical risks that carbonates present has put Schlumberger at the forefront of technology development to meet the challenges presented by carbonate reservoirs and to help our customers optimize productivity. Because of the complex nature of carbonate reservoirs, Schlumberger has a variety of solutions for optimum stimulation.
Fracturing and Completion Services

Maximize reservoir contact by applying the most efficient and effective services for each well.
Conventional | Intervention | Permanent | Dynamic
Deep-Penetrating, High-Temperature Acid

Use SuperX emulsified acid, a highly retarded HCl system, to overcome acid penetration problems in stimulating reservoirs above 250 degF [121 degC].
Viscoelastic Diverting Acid

Increase zonal coverage in carbonate reservoirs.
Technology Innovations
Degradable Diversion Acid

Incorporate dissolvable fiber and nondamaging acid in a single-step, self-diverting stimulation system, using MaxCO3 Acid.

Scale Control Services

Remove and prevent scale within wellbores and the reservoir.

Deep-Penetrating, High-Temperature Acid

Improve Your Reservoir Acidizing and Acid Fracturing Treatments

SuperX emulsion fluid for high temperatures improves your reservoir acidizing and acid fracturing treatments in high-temperature reservoirs. SuperX fluid is a viscous, highly retarded HCl system designed to overcome acid penetration problems in stimulating reservoirs above 250 degF [121 degC].

Standard hydrochloric acid reacts very quickly in carbonate formations. The reaction is so rapid in high temperatures that it is impossible for acid to penetrate, or wormhole, more than a few inches into the formation. In such cases, the acid is rendered ineffective in stimulating the well. Deep, live-acid penetration can be achieved if the acid reaction rate is retarded — a feat accomplished with SuperX emulsion high-temperature system. This oil-external emulsion is formed with a 70:30 HCl-to-oil ratio, stabilized with an emulsifier. HCl concentrations ranging from 7.5 to 28% may be used in either a batch or continuous mix system.

Reaction retardation

SuperX high-temperature emulsion is significantly retarded with respect to HCl. The retardation depends on temperature, acid concentration, flow regime (laminar, transitional or turbulent) and type of rock (dolomite or limestone). Between 250 degF and 350 degF [121 degC and 177 degC] the HCl-limestone and the HCl-dolomite reactions are mass-transfer controlled.

Emulsion stability

The stability of SuperX fluid is temperature dependent. Quality of oil phase and mixing time also affect the emulsion stability.

Viscoelastic Diverting Acid

Damage-free carbonate stimulation

VDA viscoelastic diverting acid, a self-diverting, polymer-free acidizing fluid, can be used alone or with other treating acids for total zonal coverage in carbonate reservoirs. It viscosifies as it stimulates in carbonate formations, diverting the remaining acid treatment fluid into zones of lower injectivity for

improved zonal coverage across long intervals and high permeability contrasts
extremely efficient wormholing behavior in a wide range of conditions
significantly better leakoff control than straight hydrochloric and noncrosslinked gelled acid
high fluid efficiency during acid fracturing treatments
simple mixing for a smaller equipment footprint

VES fluid technology for total zonal coverage

Diverters can cause formation damage in carbonate formations. VES viscoelastic polymer-free surfactant does not damage the formation and can be bullheaded. It is self-diverting without incurring residual damage.

Enhanced, drag-reducing properties significantly lower friction pressure to reduce pumping requirements and treat deeper zones. VES-based fluids include VDA viscoelastic diverting acid, ClearFRAC polymer-free hydraulic fracturing fluid, and ClearPAC fluid system for gravel packing.

Ideal consistency

The fluid rapidly develops viscosity in situ upon acid spending and becomes self-diverting. The viscosity reduces dominating wormholes and allows the fluid to stimulate other zones.

Reduced cleanup costs

Recovery and well cleanup are easy after treatment. The barrier is broken down by production or dilution with formation fluids. Only low pressures are required for a smoother process.

Degradable Diversion Acid

MaxCO3 Acid degradable diversion acid is an effective single-step, self-diverting stimulation system that incorporates dissolvable fiber and nondamaging acid. The hydrochloric acid (HCl)-based system offers stimulation and then flow restriction for diversion. The interlocking fiber network blocks fluid during the stimulation job, yet dissolves completely with time, allowing poststimulated production contribution from diverted areas. Able to be bullheaded or deployed with coiled tubing (CT), the MaxCO3 Acid system can be used in openhole or cased hole completions for many applications.

The MaxCO3 Acid system is part of the Schlumberger carbonate stimulation offering, which includes the Contact family of stage fracturing and completion services for efficiently maximizing reservoir contact, Deep-Penetrating, High-Temperature Acid for overcoming acidizing challenges above 250 degF, and Viscoelastic Diverting Acid for increasing zonal coverage.
Damage-prone formation in North Dakota

To stimulate a 4,800-ft lateral in the Bluell formation (prone to damage from drilling mud leakoff), the MaxCO3 Acid system was implemented for superior diversion. It improved leakoff control such that after-treatment production increased 500%—to more than 300 bbl/d from just 50.
Thick carbonate in Qatar

Uniformly stimulating the thick, heterogenic Khuff formation proved challenging for an operator. The company used MaxCO3 Acid degradable diversion for 11 treatments in the North field and consistently stimulated each zone. Treatment volumes were reduced by up to 50%, and rig and operational time were reduced by 30%.
Naturally fractured carbonate in the Caspian region

The MaxCO3 Acid system was used to optimize stimulation for a horizontal openhole lateral. The technique created and diverted multiple fractures and controlled fluid loss, resulting in a production increase twice what the operator anticipated.

Degradable Diversion Acid

MaxCO3 Acid degradable diversion acid is an effective single-step, self-diverting stimulation system that incorporates dissolvable fiber and nondamaging acid. The hydrochloric acid (HCl)-based system offers stimulation and then flow restriction for diversion. The interlocking fiber network blocks fluid during the stimulation job, yet dissolves completely with time, allowing poststimulated production contribution from diverted areas. Able to be bullheaded or deployed with coiled tubing (CT), the MaxCO3 Acid system can be used in openhole or cased hole completions for many applications.

The MaxCO3 Acid system is part of the Schlumberger carbonate stimulation offering, which includes the Contact family of stage fracturing and completion services for efficiently maximizing reservoir contact, Deep-Penetrating, High-Temperature Acid for overcoming acidizing challenges above 250 degF, and Viscoelastic Diverting Acid for increasing zonal coverage.
Damage-prone formation in North Dakota

To stimulate a 4,800-ft lateral in the Bluell formation (prone to damage from drilling mud leakoff), the MaxCO3 Acid system was implemented for superior diversion. It improved leakoff control such that after-treatment production increased 500%—to more than 300 bbl/d from just 50.
Thick carbonate in Qatar

Uniformly stimulating the thick, heterogenic Khuff formation proved challenging for an operator. The company used MaxCO3 Acid degradable diversion for 11 treatments in the North field and consistently stimulated each zone. Treatment volumes were reduced by up to 50%, and rig and operational time were reduced by 30%
Naturally fractured carbonate in the Caspian region

The MaxCO3 Acid system was used to optimize stimulation for a horizontal openhole lateral. The technique created and diverted multiple fractures and controlled fluid loss, resulting in a production increase twice what the operator anticipated.