Damage wellbores

A reduction in permeability around the wellbore mainly caused by contact with drilling fluid (formation damage]. 

Filter-cakes are hard to remove and thus can cause considerable formation damage. Cakes with very low permeability can be broken up by reverse flow. No high-pressure spike occurs during the removal of the filter-cake. Typically a high-pressure spike indicates damage to the formation and wellbore surface because damage typically reduces the overall permeability of the formation. Often formation damage results from the incomplete back-production of viscous, fluid loss control pills, but there may be other reasons. 

Enzymes to degrade crosslinked hydroxypropylated starch derivative and xanthan gum polymer systems are available [158,1246]. Specific enzymes are efficient in reducing the near wellbore damage induced by the starch polymer to eventually return permeabilities to the range of 80% to 98% without the use of acid systems. 

After cementing the well, communication must be established with the productive formation. This is done in an operation called perforating. The wellbore is filled with a non-damaging fluid of... 

Fluid loss from the wellbore to the formation may be reduced using the less permeability damaging drilling fluid loss additives described above. In saturated brines, carefully sized sodium chloride particles have been used to temporarily plug the formation face (35). The particles may be dissolved by pumping a less saline fluid down the wellbore. 

The region near the wellbore acts as a choke for the entire formation because the flow is radial more and more fluid is flowing through a given volume of rock as the fluid approaches the well bore. The reduction of the rock fluid carrying capacity is referred to as formation damage. 

Reduced injectivity due to formation damage can be a significant problem in injection wells. Precipitate formation due to ions present in the injection water contacting counterions in formation fluids, solids initially present in the injection fluid (scaling), bacterial corrosion products, and corrosion products from metal surfaces in the injection system can all reduce permeability near the wellbore (153). The consequent reduced injection rate can result in a lower rate of oil production at offset wells. Dealing with corrosion and bacterial problems, compatibility of ions in the injection water and formation fluids, and filtration can all alleviate formation damage. 

The dissolution channels (wormholes), obtained under certain conditions of attack of carbonate rocks by hydrochloric acid, have been recently proven to have a fractal geometry. An equation was proposed, relating the increase of the equivalent wellbore radius (i.e. the decrease of the skin) to the amount of acid injected, in wellbore geometry and in undamaged primary porosity rocks. This equation is herein extended to damaged double porosity formations through minor modifications. 

Injecting acid in such an interval produces wormholes in the nearwellbore region, which is damaged, so that the acid flow only takes place in the clean primary porosity of the rock. This superposes to the original step function of the permeability profile a second, similar function, stating that the acidized profile now includes in the vicinity of the wellbore, from rw up to re, a zone of infinite conductivity... 

Figure 1 Permeability profile in a damaged double porosity reservoir during acidizing. rw wellbore radius, re wormholes penetration, damage radius, kptp undamaged reservoir permeability (total contribution of both primary and secondary porosities), kPP damaged permeability (primary porosity contribution only).

There is considerable potential, therefore, for mineral scale, such as barium sulfate (see the next section), to form during these procedures. The scale may be deposited in the formation, the wellbore, or in production tubing. Scale that forms in the formation near wells, known as formation damage, can dramatically lower permeability and throttle production. When it forms in the wellbore and production tubing, mineral scale is costly to remove and may lead to safety problems if it blocks release valves. 

In the simulations, a significant fraction (about 50% to 80%) of the alkali present in solution is consumed by reactions near the wellbore with the reservoir minerals (as shown in Reaction 30.6 for the NaOH flood), mostly by the production of analcime, paragonite, and dawsonite [NaAlC03(0H)2]. In the clastic reservoir considered, therefore, alkali floods might be expected to cause formation damage (mostly due to the precipitation of zeolites) and to be less effective at increasing oil mobility than in a reservoir where they do not react extensively with the formation. 

In a manner similar to carbonate precipitation in fractures, wellbore-scale precipitation and formation damage occur due to pressure release in hydrocarbon-producing wells (Fisher Boles, 1987). 

Stimulation of a well is accomplished by increasing the flow capacity near the wellbore and allowing formation fluids to enter the wellbore more easily. When low permeability exists, when formation is damaged, or when altered native reservoir characteristics around the wellbore exist, near wellbore stimulation may be beneficial. 

Foamed Matrix Acidizing. Matrix addizing is a stimulation treatment used to remove damage near the wellbore without deating a fracture. The process involves the injection of a reactive fluid into the porous medium at a pressure below the fracturing pressure. The fluid dissolves some of the porous medium and consequently increases its permeability. 

Injection waters used in the oil industry may be taken from various sources seawater, fresh water, subterranean water, and production water, which was initially brought to the surface with the crude oil. Injection waters may contain different kinds of particulate materials (formation particles, corrosion products, insoluble carbonates, or sulfates, iron compounds, oil-in-water emulsions, and bacteria) that may be deposited in the rock pores. Because this deposition may lead to well impairment, injection water may have to be treated before it is injected. Oil-producing wells can also be damaged during drilling or workover. Solids present in drilling muds and workover fluids can invade the formation and damage the wellbore area (3, 10, 24, 25). 

Invasion of Foreign Particles. Invasion of solid particles can cause severe damage around the wellbore. In this case, the solids plug some of the pores and, as a result, the formation permeability diminishes. According to Wojtanowicz et al. (71), the decline of permeability with respect to time can give an indication of the plugging mechanism. At a constant flow rate experiments, the pressure response that occurs due... 

Invasion and Drilling Related Formation Damage. The influx of particulates and filtrate into the near wellbore region of permeable formations during static or dynamic filtration has a number of consequences, two of the most important being displacement of wellbore... 

Liu Y. 1995. Mud density for wellbore stability when formation rock is damaged. Acta Petrolei Sinica, Vol. 3, pp. 123-128. 

COUPLED ANALYSIS OF DAMAGE FORMATION AROUND WELLBORES... 

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