Monday, July 30, 2018


The purpose of doing fracture stimulation on a well is to increase the production rate of that well. This is done by improving the natural drainage conditions around the well bore. This is called improving natural conductivity.

Fracture stimulation involves pumping a fluid down the well at high pressure. This causes rock in the vicinity of the well bottom to fracture (to split or crack). Vertical fractures can be induced ranging in length from a few meters to some hundreds of meters.

Fracture widths are in the range of a few millimeters. The fractures open up drainage channels to the well bore. This increases the exposed face of the reservoir rock.

Fluids pumped are selected according to the type of rock to be fractured. Formation with solubilities less than 50% are more often fracture stimulated with water or oil based fracturing fluids. These are normally sandstone type formation.

Fluid Injection


The function of a "proppant" is to prevent the fractures created during fracture stimulation from closing up again once the fracturing pressure is released.

Selective graded sand is the most commonly used proppant. The main considerations for selecting a proppant are:
  • The proppant material must resist crushing under high overburden pressure. Overburden pressure is the weight of rock above the fracture.
    • The proppant material must resist being embedded in soft reservoir rocks.
    Proppant sand grains are graded by passing the grains through different sized sieves (meshes). Large grains and undersize grains are removed.


    Fracturing fluids must have the following properties:
    • The ability to carry and correctly place adequate of proppant.
    • Low fluid loss (The fluid must not enter the formation rock).
    • Low frictions loss (The fluid must be easily pumped).
    • Compatibility with the formation and formation fluids. The fluids must not cause swelling of shales (clays) or form emulsions with formation fluids.
    • Have rapid clean-up ability (easily flow back out of the formation).

    Fluids Additivies

    There are many additives that can be used with fracturing fluids to obtain these properties. Natural gums, cellulose gums and polymers are used to increase fluid viscosity and to form gels. These also act as a spacer between the proppant sand grains.

    The gels can be made to last for any period of time up to 100 hours. Once the gels break (return back to low viscosity fluid), it is easy for the fracturing fluid to flow back during well clean up.

    Most of these gelling additivesn also act as friction reducers.

    Low Pressure Ground Mixer Assembly


    Fracturing fluids may be batch mixed or continuously mixed.

    In batch mixing, all the fluid to be used on the job is pre-mixed before the job started. This requires large storage volumes and carefull consideraion of gel life and gel strength.

    In continuous mixing, the fluid is mixed as it is needed during the job. If a downhole problem is met during fracturing, unmixed material can be used later or onather job.


    The basic equipment requirements are:
    • Storage tanks - contain the raw materials that will be mixed together to make up the fracturing fluid.
    • Proportioners - take the raw materials and feeds them to be mixed in the correct proportions.
    • Blenders - does the mixing of the raw materials with the water or oil that will be pumped.
    • Pumps - inject the completed fracturing fluid down the well.



    The purpose of doing acid stimulation on a well is to increase the production rate of the well. Production rate will increased by increasing the permeability of the formation rock near to the well bore.
    The permeability of a rock is the ability of that rock to allow fluids to pass through that rock. The higher permeability, the easier it is for fluids to pass through the rock. The lower permeability, the more difficult it is for the fluids to pass through the rock.
    The pores or holes in the formation are known as the "matrix". Acid stimulation is also called "matrix stimulation". Most acid treatments fall into one of three general classifications:
    • Wellbore clean up - is mainly flooding the wellbore adjacent to the perforations to remove scale and drilling mud solids.
    • Matrix acidising - consist of slowly pumping acid into the formation so that the acid penetrates the pore spaces without fracturing the formation rock. This procedure is normally carried out to dissolve mud and drilling contaminants from soft sandstone formations.
    • Fracturing - involve the injection of acid at rates faster than the natural flow channels can accept it until the formation rock finally fractures or splits. As the treatment continues, the acid moves through the fractures and dissolve extended pits and channels through the rock face.
    Type of Formation Damage


    The two acids most commonly used for oil well stimulation are:
    • Hydrochloric Acid (HCl)
    • Hydroflouric Acid 9 (HF)
    After these acids have "dissolve" the formation rocks and contaminants the products of that chemicals reaction must be soluble.
    If the reaction products were not soluble, the solid materials produced would block and plug the pore spaces in the formation rock and reduce permeability. The mixture of acids and additives are specifically engineered for each well and each type of formation. The pumping pressures and volumes are also spesifically engineered for each formation.


    Different chemicals are added to the basic acid mixture that is pumped down the well. There are many different additives used for many different reasons.
    Basically we want the acid to attack the formation rock and the contaminants in it. We do not want the acid to attack the completion equipment nor do we want the acid to be used up (spent) before it gets into the formations. The acid must also be easy to pump. The main types of additives are:
    • Retardant - which delay the action of the acid to give it time to reach the place where we want it to do it's job.
    • Friction reducer - which make the acid mixture more slippery and easier to pump.
    • Surfactants - which make it also easier to pump the acid. They also help to prevent emultions of the formation once the acid has done its job and is mixed with any oil in the formation. We have to be able to recover all the spent acid and reaction products once the stimulation job is finished.


    These are hard plastic or hard rubber balls with a negative bouyancy. They do not float in the acid. The Perf-Pac Balls are pumped down the well with the acid at different time intervals during the acid job.
    Some of the larger perforations will accept the acid then the others. If we are not careful, all the acid will go into the easy or larger perforations. Fluids always flow the easiest way.
    Perf-Pac balls will travel with the acid being pumped and will plug off the larger perforations that are accepting the acid. This then forces the acid go through the more difficult or smaller perforations.
    When the acid stimulations is complete and pumping has stopped, the Perf-Pac balls will fall to the 
    bottom of the well.


    How far the acid penetrates into the formation is very dependent on how fast we pump the acid. More fast we pump the acid, the less time it is contact with rock as it enters the formation. Live acid therefore goes further into the formation where it can attack the formation rock or contaminants.

    Effect of Injection Rate on Perforation
    Effect of Damage Zone on Productivity


    Formation damage occurs during the drilling of the well. The rock is crushed by the drilling action and driling fluids enter the formation. The formation is therefore damaged close to the wellbore. Most damage occurs within a radius of one foot of the wellbore. The damage is also called "Skin Effect". Maximum damage occurs within three feet of the wellbore.

    Saturday, July 28, 2018



    When the formation pressure is not high enough to overcome the hydrostatic head (the total weight) of the fluid in the well tubing, the well will not flow. This situation can exist in a newly-drilled well. It can also exist in an old well where the Bottom Hole Pressure (BHP) has decreased due to production. Gas lift can be used in both these case to make wells flow.
    Hydrostatic pressure : the pressure exerted by a column of fluid due to the height of the fluid and the specific gravity of the fluid.
    Gradient : the pressure exerted per unit of vertical height of a fluid (gradient increases as specific gravity of the fluid increase). 
    Basic Components for A Gas Lift System


    To reduce the hydrostatic head of the fluid in the production tubing so that the formation pressure will be great enough to make the well flow. This is done like this:
    • Gas is introduce into the oil in the tubing as deep as possible. This is normally done from the casing tubing annulus into the production tubing.
    • As the gas mixes with the oil, it "aerates" the oil (fills the oil with small gas bubbles). This reduce the specific gravity of the oil, which means that the gradient has also been reduced.
    • By reducing the gradient, the hydrostatic pressure will be less than the formation pressure at bottom hole. The well will flow.
    • As the mixture of oil and gas bubbles moves up the tubing, the tiny bubbles of gas expand. This reduces the hydrostatic pressure further and thw well flows more easily.


    A source of clean, liquid free gas is needed. This can come from a nearby gas well 
    or from a gas/oil separation plant. This gas lift gas has to be compressed to a high 

    The gas is introduced into the annulus of the well to be lifted, through a regulating 
    device at the surface. The regulating device can be a choke or a flow controller.

    The amount of gas injected has to be controlled because:
    • If there is too little gas, the well will not flow oil.
    • If there is too much gas, the gas will come out of the oil in the production tubing and pass to the surface as free gas taking no oil with it.

    Produced oil plus the gas is used to lift the oil flow from the well at the surface. This
    production oil is flowed through a separator to remove the gas from the oil. The oil 
    is passed on to production process or to storage.

    The separated lift gas plus separated formation gas produced with the oil is passed
    through a scrubber to remove any liquids. It is then recompressed to be used 
    again  for the gas lift cycle or it is passed to the gas processing plant.

    This is a continuous process.

    Dual ‑ String Gas Lift Installation
    Gas Lift Sequence

    Unloading Sequence in a Well to be Gas Lifted:

    Sequence is numbered 1 through 9 as below.

    Note:         All gas lift valves are tubing sensitive.

    1.     Well is ready to unload with casing and tubing full of fluid. All gas lift valves are open.

    2.     Gas pressure has U‑tubed fluid from the annulus to production tubing through the gas lift  valves. Gas has not yet entered the production tubing which is still full of original fluid.

    3.     Annulus fluid level has been lowered below the first valve and gas has entered the production tubing through the first valve. From this moment gas lifting of the tubing contents commences. Formation flui feed‑in has not yet commenced.

    4.     Annulus fluid level has been lowered by U‑tubing to just above the second valve. Gas lift injection into the tubing is continued at the first valve only.

    5.     Annulus fluid level has been lowered below the second valve and gas enters the tubing through the second valve. As flow commences from the second valve the tubing pressure gradient opposite the first valve decreases and the first valve closes. At this step in the unloading sequence the back pressure on the formation has been decreased to the point where formation fluid starts flooding into the well. The fluid in the tubing is slowly displaced from the formation. The formation fluid will continue to be mixed with load fluid as the annulus continues to unload.

    6.     The annulus fluid level has been lowered to just above the third valve. The transfer of fluid from the annulus to the tubing is the only change in the conditions established in (5).

    7.     Annulus fluid level has been lowered to below the third valve, and gas enters the production tubing through the third valve. As flow commences through the third valve the production tubing pressure gradient opposite the second valve decreases and the second valve closes. Injection of gas through the third valve lowers the back pressure on the formation further and additional formation fluid flows into the production tubing.

    8.     Annulus fluid has been lowered to just above the fourth valve. The transfer of fluid frorn the annulus to the tubing is the only change in, the conditions established in (7).

    9.     The fourth and deepest valve has been uncovered and gas  injection commences at this point. The third valve closes and flow from the formation stabilises at the maximum rate possible for the installations.


    The principle by which a gas lift system operates can also be used to start a well 
    flowing. It will 'kick off' a well.

    With 'dead' crude in the well, (crude containing no gas), the hydrostatic pressure
    exerted by that crude can be greater than the formation pressure. The well will not 

    Gas is introduced into the well as deep as possible. This aerates the crude thereby
    enabling it to flow.

    Once the well is flowing with 'live' crude in the tubing, the well will continue to flow
    without the assistance of injection gas.

    The gas, natural gas or nitrogen, is introduced deep down into the tubing through a 
    long, small pipe inserted down the production tubing. This requires special 
    equipment called a 'coiled tubing unit', and the technique is used extensively,
    especially after workover and well stimulation operations.

    Kickover Tools 

    To simplify the wireline work to install gas lift valves in side pocket mandrels, a specially designed kickover tool can be used. This too[ locates the mandrel selectively when two or more mandrels are installed in one well. It also orients in the proper position and offsets the valve (or pulling tool) into position over the pocket for setting or retrieving the valve.

    Kickover Tools for Installing Side Pocket Mandrels
    Schematic 1
    The kickover tool is run below the mandrel. Since the tool is locked in a rigid
    position, it is designed to not kick over accidentally.

    Schematic 2
    The kickover tool is raised until its key engages the kickover sleeve in the mandrel.
    Continued upward movement rotates the tool until its key enters a slot. When the 
    key reaches the top of the slot, the operator is notified by a weight increase 
    displayed on the weight indicator. The tool is now properly oriented.

    Schematic 3
    The pivot arm is designed to swing and lock in position. This action locates the
    valve or pulling tool above the pocket or latch on the gas lift valve.

    Schematic 4
    The mandrel is designed to guide the valve or pulling tool to accurately land the
    valve or engage the latch on the valve.

    Schematic 5
    A straight upward pull shears a pin when the key reaches the top of the slot. This
    action allows the trigger to guide freely out of the slot and through the tubing. When
    the pivot arm reaches the small upper section of the mandrel, it is designed to
    snap back and into its vertical running position. This reduces the drag on the tool 
    and the valve as it is removed.

    Side Pocket Mandrel


    These valves are used down‑hole in the well and stop or start the flow of gas lift 
    gas or fluid from the annulus into the production tubing.

    ·           There are generally two basic types in use.

    ·           Tubing pressure operated.

    ·           Casing (annulus) pressure operated.

    The pressure exerted against the gas lift valves at depth from the tubing or the 
    casing opens the valves. The valve opening pressure is pre‑set at the surface 
    before the valves are run into the well.

    These valve opening pressures are calculated during the design stage of the gas 
    lift system. The deeper the valve in the well the higher the operating pressures.

    Tubing Pressure Operated

    When hydrostatic pressure near to the valve in the tubing is greater than the
    pre‑set valve opening pressure, the valve will open. This will allow gas/liquid to 
    flow through the valve from the annulus to the production tubing.

    When hydrostatic pressure near to the valve in the tubing falls below the 
    pre‑set valve opening pressure, the valve will close. Flow from the annulus 
    to the tubing will then stop.

    Reverse flow through the valve from production tubing to annulus is prevented
    by a check valve in the valve.

    The check valve is flow sensitive ‑ not pressure differential sensitive.

    Tubing Pressure Operated Gas Lift Valve

    Casing Pressure Operated

    The function of the valves are identical to the tubing pressure operated except that
    it is the casing or annulus pressure adjacent to the valve that activates the valve
    to open or close.
    Casing Pressure Operated Gas Lift Valve
    Chemical Injection from Casing

    Friday, July 27, 2018


    Oil and gas wells can be serviced by the use of tools and devices run into the wells on a length of circular cross‑section steel line mounted on a powerful reel at the surface. ‑This is called a wireline unit.

    Operations that can be done by 'running' or 'pulling' the tools and equipment into and out of the well
    bore by using a wireline are listed below.

    ·           Measure the depth of the deepest well.
    ·           Accurately measure bottom hole pressures and temperatures.

    ·            Carry out gradient pressure and temperature surveys.

    ·           Obtain fluid samples at any point in the well for laboratory analysis.

    ·           Check tubing internal dimensions, used to aid in the detection of corrosion or scale

    ·           Remove wax and sand deposits.

    Besides the jobs listed above, a large number of special tools and equipment can be set, retrieved, or
    moved to change the well status.


    ·           It is more economical to use a wireline for workovers than a drilling rig because:

    ·            A wireline unit can move onto the well site, rig up, do its job, rig down, and move off to
           another well site in less time than a drilling rig.

    ·           A wireline unit requires‑only 2 or 3 operators.

    ·           A wireline unit normally requires no outside services or assistance to do its job as it is
           self‑sufficient. In fact, wireline units are used as a support service to drilling and workover


    Wireline operations involve a large risk of failure if not done correctly.

    This risk is due to the fact that the wireline specialist is working 'blind'. He has sensors and indicators
    at the surface but he still has to operate tools and equipment that are on the end of a length of wire
    several thousand metres away at the bottom of a hole in the ground.

    The operator has only two movements available to him:

    ·           He can run more wire into the hole.

    ·           He can pull wire out of the hole.

    Simply put, he can only move his tools up or down.

    This risk is minimised by keeping good well records and maintaining all tools and equipment to the
    highest standards.


    This is the piece of equipment that operates the reel that contains the wireline.


                Prime Mover (driver)

                   This unit supplies the hydraulic power. It consists of a diesel engine that drives a hydraulic pump.

                Reel Unit

                      The reel unit receives the flow of hydraulic oil from the pump via hoses and converts that
              flow into rotational movement through a hydraulic motor.‑ The hydraulic motor rotates the reel that contains the wireline. Rotational movement direction is controlled through a 4‑ valve. Hydraulic horsepower (tension on the wireline) is controlled by a manually set, combination pressure regulator/bypass valve.

                The line tension (pull on the line) and line speed can be varied through a very large range. The line direction, running into the well or pulling out of the well, can be changed instantly by movement of the 4‑way valve control handle. This can be compared to a car travelling forward at 100 kph and instantly changing direction to reverse at 100 kph. Such movements of the wireline are required when unexpected problems occur down the hole. This is done to prevent the wireline from breaking.


                Many problems can occur while using the wireline. Some problems are caused by OPERATOR ERROR but others are UNPREDICTABLE PROBLEMS.

                Operator Error Problems


                Placing too much tension on the wire may cause it to break if its strength is exceeded.

                Running an incorrect tool.

                This may cause the tool to become stuck down the hole or fail to do its job.

                Using the incorrect wire grade for the well conditions.

               This can cause corrosion or embrittlement (becoming easy to break). If the wire then breaks it can fill the hole with small bits of wire.

                 Not equalising the pressure across the downhole devices.

                This can cause the tool string to be blown up, or blown down the hole, resulting in broken wire  and wire stuck in the hole.

                Running a tool that is damaged or not correctly prepared.

                This can cause the tool to be stuck down the hole or fail to do its job.

                Running wireline that is too old.

                This can cause the wire to break.

                Note :               All these problems can be put down to 'operator error', a man‑made mistake,

                The success of the operation depends on the skill and experience of the wireline specialist

               Unpredictable Problems

    ·           A downhole device can malfunction.

    ·           A downhole device can break due to metal fatigue or because it has become brittle.

    ·           The downhole tubing can collapse or partially collapse trapping the tools.

    ·           The tool or device that is thought to be in the well is not where it should be or it is of a different type than expected. (Well records are incorrect.)

    ·           There is a tool or device in the well that should not be there. (Well records are not up to date.)


                The diameter of the wireline depends on several factors.

                The wireline is subjected to pressures ranging from a few pounds to several thousands of pounds per square inch. This pressure pushes against the cross sectional area of the wireline. If large diameter wireline were used, the weight needed to pull the wireline down the hole against this force would be too much. The small diameter wireline is elastic and this elasticity ‘s needed to assist in operating downhole devices. The large diameter wireline would also require large diameter reels and sheaves as the minimum bending radius of that wire would have to be large as well.


    Ball Type Valves
    The only function of a Sub‑Surface Safety Valve (SSSV) is to automatically and reliably
    close in the well below the surface of the earth when there is an emergency.

    It is an international requirement that offshore wells are fitted with SSSVs.

    • If the land wells in Kuwait had been fitted with SSSV, the damage to oil reservoirsand the environment in Kuwait would have been much less. All the oil fires would have gone out due to lack of fuel.

    • There were no major fires on the platforms offshore Kuwait where the SSSV  performed their function even when the wellheads were destroyed.

    SSSV can be retrieved from the well using a wireline unit (wireline retrievable) or they can be part of the tubing string.


    Safety Valve Landing Nipple
    The SSSV are landed and locked into a special landing nipple in the tubing string. This landing nipple has two polished bores with a port between. The port is connected to the wellhead by stainless steel, small diameter tube, and then to a hydraulic control panel.
    Hydraulic Control Lines

    The SSSV locates into the landing nipple and the two sets of seals on the outside of the
    valve seal in the two polished bores. A port in the outside of the SSSV then joins with the
    port in the landing nipple.

    As additional control line pressure is applied, the valve moves to the fully open position. Control line pressure is maintained at the control panel to keep the valve in the fully open position.

    Hydraulic control pressure can be applied from the surface into the SSSV where it acts
    against an annular‑shaped piston, then the piston moves and opens the valve.

    When this control hydraulic pressure is released, a strong spring in the SSSV pushes back
    the piston to close the valve. The spring force must be stronger than the weight of the
    control fluid and the friction inside the SSSV. There is therefore a limit to how deep these
    SSSV can be set in the wells.


    There is always a differential pressure across a closed SSSV. This is because of the gas
    and fluid in the tubing above the valve and the increase in pressure below the valve (due to
    the natural build‑up of pressure from the well).

    Pressure across the valve must be equalized before the valve is opened. There are
    equalizing ports in the valves to do this.

    Control line pressure is applied to the valve from the surface control panel.

    The well head pressure is monitored as the control line pressure is slowly increased. An
    increase in wellhead pressure will show when the equalizing ports in the valve have been

    The control line pressure is kept at the level that caused the equalizing ports to open.

    When the wellhead pressure is stabilised, (no more increase in pressure over a 15 minute
    period), we can say that there is no pressure differential across the SSSV.

    This equalizing action prevents any damage to the sealing elements of the valve.


    • Considerable damage can be done to an SSSV when it has not been equalized before applying full opening control line pressure.
    • Valve damage will not be known until the SSSV is pulled from the well or until the SSV is needed to perform its function in an emergency. IT WILL LEAK BADLY and there will be NO ISOLATION from reservoir pressure in an emergency.

    Ball Type Safety Valve
    Flapper Type Safety VaIve
    Piston Action


    The purpose of doing fracture stimulation on a well is to increase the production rate of that well. This is done by improving the natura...