Introduction Stimulation is a chemical or mechanical method of increasing flow capacity to a well. Stimulation methods can be used in production, discovery and appraisal wells. The purpose of stimulation is to restore or enhance the delivery of hydrocarbons to the wellbore. Wellbore will halt the production of the hydrocarbons after perforating because permeability has been decreased and wellbore region has been damaged due to specific reason. In a general case, it can be called as formation damage. Introduction Oil and gas well is produced for many years without the consumption of well stimulation technique. As an oil and gas well is put on the production, this is at its highest rate from the initial stage. As the time passes by, production reduces by certain reasons, pressure declines. Well stimulation services are utilized to help to restore the original pressure in order to increase production and bring production back up. Introduction In today’s society, the demand for oil and gas has rapidly increased, which means production also needs to increase to keep prices affordable and maintain pace with the demand. To do this, new techniques are needed to maximize production. When a well is initially drilled and is put on production, oil production continues without any depletion for years However, oil and gas drilling introduces foreign materials, such as clay and water. Formation Damage Formation Damage Formation damage is defined an impairment to the reservoir caused by the invasion of wellbore fluids during any interval of well. In petroleum industry, it is said that "Formation damage is an expensive headache to the oil & gas industry Formation Damage Formation Damage Formation damage causes the formation permeability to go down in the wellbore region. Formation damage can occur due to multiple reasons which will be discussed later. The reduction in the permeability of wellbore region will affect in the reduction of productivity of the well. Pore throats in the near wellbore region are blocked. And this blockage caused the flow area to decrease. Another reason for reduced flow area is to have turbulent flow. When turbulent flow happens in the well, this causes much pressure drop in comparison with same flow. Pressure drop in the turbulent flow is higher than Darcy flow which result in reduction in the wellbore permeability. Formation Damage Formation Damage Natural • Occurs as produced reservoir fluids move through the reservoir • Is the result of external operations and fluids in the well such as drilling, well Induced completion, or workover operations. Formation Damage Formation Damage Formation Damage Figure shows dependence between filter cake permeability and rate of invasion Formation Damage Inorganic Scale – Scale is the precipitation of the inorganic and organic mineral. During water injection process, scale can form when two water are incompatible with each other. While sea water contains the high concentration of the sulfate ions, formation water contains calcium, barium ions. Calcium sulfate, barium sulfate can precipitate in the tubing, bottomhole, perforations, in the accessories inside tubing. Figure shows the blockage inside tubing by scale precipitation. Formation Damage Precipitation can block the perforations and reduce wellbore permeability. Scale inhibitor is used as prevention method to remove scale precipitation from damaged zone. Scale inhibitor is injected into formation and dissolved the precipitation and retrieved with formation fluids. Organic Scale – Some crude oils can lead to solid precipitation which is known as wax. When the temperature goes lower than cloud point temperature, wax (solid precipitation) reveals. When reservoir temperature is kept higher than cloud point, the solid phase is dissolved in the crude oil. To prevent this solid phase to form, scale inhibitor is used as mentioned before. Formation Damage Formation Damage Production log is used to measure the production capacity and flow rate. This is one method to be aware of having formation damage. It is given information of the sand quality to be able to measure flow rate. From this graph, it is shown that upper and middle sands represent high flow rate. Being different from up and middle, bottom sand represent lower flow rate. Bottom sand can have formation damage and blocked pores. But of course, lower flow rate can not indicate formation damage, this can indicate that, this can be depleted formation and depleted reservoir pressure Figure shows log determine the zone having formation damage. Formation Damage 1. Mechanical Damage 2. Chemical Damage Formation Damage The formation damage that is caused by plugging of solids or grain particles with the pore space or throats of the formation rock which ultimately results in the impedance to the flow of fluid. Formation Damage Injection of low salinity water into a sandstone reservoir could result in clay swelling & fines migration. Injection of incompatible water (contains high sulphate content) & the formation water contains high concentration of calcium, strontium or barium ions. Formation Damage Pores are open spaces between the particles of a rock. Pores may contain air, gas, or liquid (water or oil). The more pore space, the higher the porosity. The more "connected" the pores, the higher the permeability. Pore fluids will flow more easily in rocks that are more permeable Formation Damage The processes of drilling, completing and producing an oil or gas well include many mechanical, hydraulic, and chemical processes. Many wells are drilled overbalanced, so that drilling fluids migrate into the near-well area. The fine particles in the muds may plug pore throats, or the filtrate may react chemically with clays in the formation – either of these processes can reduce the near-well permeability dramatically. Formation Damage Completions may further reduce the productive capacity of the well: the well may be cased and perforated (reducing the inflow area compared to an open-hole completion). On the other hand, the pressure-drop in the near-well area can sometimes be increased. This could be accomplished by fracture treatments or acid treatments. Attempts to lower the pressure drop in the near-well area are often called “stimulation.” Formation Damage Over the last five decades, a great deal of attention has been paid to formation damage issues for two primary reasons. Ability to recover fluids from the reservoir is affected very strongly by the hydrocarbon permeability in the near-wellbore region Although we do not have the ability to control reservoir rock properties and fluid properties, we have some degree of control over drilling, completion, and production operations Thus, we can make operational changes, minimize the extent of formation damage induced in and around the wellbore, and have a substantial impact on hydrocarbon production. Being aware of the formation damage implications of various drilling, completion, and production operations can help in substantially reducing formation damage and enhancing the ability of the well to produce fluids. Formation Damage The most commonly used measure of formation damage in a well is the skin factor, S. The skin factor is a dimensionless pressure drop caused by a flow restriction in the near-wellbore region. It is defined as follows (in field units): Formation Damage The following figure shows how flow restrictions in the near-wellbore region can increase the pressure gradient, resulting in an additional pressure drop caused by formation damage (Δpskin). In 1970, Standing introduced the important concept of well flow efficiency, F, which he defined as Figure shows pressure profile in the near-wellbore region for an ideal well and a well with formation damage. Reservoir Deliverability System Well deliverability is determined by a well's inflow performance. The Inflow Performance Relationship (IPR) is defined as the functional relationship between the production rate and the bottom hole flowing pressure. Productivity Index (PI or J) expresses the ability of a reservoir to deliver fluids to the wellbore. Productivity Ratio (PR) is the ratio of actual productivity index to the ideal productivity index where skin, s = 0. Reservoir Deliverability System Skin Factor The well skin effect is a composite variable. In general, any phenomenon that causes a distortion of the flow lines from the perfectly normal to the well direction or a restriction to flow (which could be viewed as a distortion at the pore-throat scale) would result in a positive value of the skin effect. Positive skin effects can be created by “mechanical” causes such as partial completion (i.e., a perforated height that is less that is less than reservoir height) and inadequate number of perforations (again , causing a distortion of flow lines), by phase changes (relative permeability reduction to the main fluid) , turbulence, and, of course, by damage to the natural reservoir permeability. Skin Factor A negative skin effect denotes that the pressure drop in the near-well bore zone is less than would have been from the normal, undisturbed, reservoir flow mechanisms. Such a negative skin effect, or a negative contribution to the total skin effect, may be the result of matrix stimulation (the near-well bore permeability exceeds the normal value), hydraulic fracturing, or a highly inclined well bore. Skin Factor The Skin measures the severity of the formation damage. Formation damage reduce permeability around the wellbore. The following figure represents ideal pressure profile of the well. This graph shows that how formation damage skin affects to create additional pressure drop. Yellow line shows the pressure profile of the damaged well. Figure shows the Effect of the skin on pressure profile . Skin Factor Skin Factor
