Sources of formation damage

The mechanisms by which rock loses permeability are covered in the lesson on formation damage. They are plugging of channels by particles, swelling and migration of clays, deposits of salts and organic matter, and water and emulsion blocks. That lesson also shows how damage is expressed as a skin. This lesson answers a different question: where and when damage happens. The answer decides how to treat it and how not to create it again.

Two practical conclusions follow from the table. First, damage from different operations adds up. A well can carry the cake from drilling, the compacted zone around the tunnels, and salts that came out after water breakthrough. So we break the measured skin down not only into its components (Skin factor) but also into sources. Second, the depth of the damage decides whether the perforation will bypass it (Formation damage and damage skin) and how much fluid we need to remove it (Acid systems and treatment design).

While the reservoir is being opened, the pressure of the drilling fluid is higher than the reservoir pressure. Large particles of mud and cuttings stop at the wall and build an external cake. Smaller particles enter the pores and form an internal cake, from millimetres to a few centimetres deep. This plugging of pores by particles is called bridging. Particles that are added to the mud on purpose, to seal the pores quickly, are called bridging agents. Which particles go where depends on their size compared with the pore throats (the narrow channels between the pores) (the rule for choosing bridging agents). In fractures and in very permeable rock, the cake has no time to form, and the whole drilling fluid goes into the reservoir.

Filtrate flows through the cake into the reservoir. Its volume depends on the properties of the cake, the overbalance (the amount by which the well pressure exceeds the reservoir pressure), and the time the hole stays open. Most of it goes in during circulation (while the drilling fluid is pumped round the well), when the flow erodes the cake (Borehole environment: invaded zone and mudcake). The depth of invasion depends on porosity (the share of the rock that is pores). The same volume goes further in tight rock (Borehole environment: invaded zone and mudcake). The filtrate does harm in several ways:

• Swelling of clays. Smectite (a clay that swells in water) and mixed-layer minerals (clays built of layers of different kinds) take in water between their layers and narrow the channels. They do this most with fresh water, and when sodium is the main exchangeable cation (the ion held loosely on the clay surface) (hydration and swelling of clays).
• Detachment and transport of clay particles (clay dispersion). When the salinity of the water in the pores (how salty it is) falls below a critical value, electrical repulsion tears particles of kaolinite and illite (two common clay minerals) away from the grains, and the flow carries them to the narrow channels. This “salt shock” is dangerous even where there is no smectite. An alkaline filtrate (high pH, the opposite of acid) makes the detachment stronger.
• Water block. The filtrate raises the water saturation (the share of the pore space filled with water) near the wellbore, and the phase permeability to oil and gas (how easily they flow when water is also in the pores) falls. In tight and gas reservoirs, capillary forces (the forces that hold liquid in tiny pores) hold the water for months.
• Emulsions and a change of wettability. Surfactants in oil-based muds (Oil-based muds), and the mixing of filtrate with oil, give thick emulsions (mixtures of tiny droplets of one liquid in another). Surfactants that stick to the grains make the rock hydrophobic (water-repelling).
• Deposits. The filtrate may be incompatible with the formation water. Carbonates and sulfates from the filtrate, together with calcium, barium and strontium from the formation water, form insoluble salts.
• Polymers. The large molecules of thickeners stick to the pore walls and stay in the channels as films and clumps.

We prevent this damage by the choice of drilling fluid and of the way the reservoir is opened. Keep the overbalance small, within the limits that the well control rules allow. Keep the time the reservoir is open short. Use a drilling fluid for opening the reservoir with bridging agents that dissolve in acid or water. Use a filtrate that is compatible with the clays and the formation water: one with potassium or ammonium, and with enough salinity (inhibitive muds, which keep clays from swelling). Where the stability of the hole and well control allow it, drill underbalanced (with the well pressure below the reservoir pressure). The fluid is chosen together with the design of the well bottom (Formation damage and damage skin).

Laboratory tests answer two questions: will this fluid damage the reservoir, and by how much? The main one is the test of return permeability. First, reservoir fluid is pumped through a core sample. Then the sample is exposed to the fluid under test. After that, reservoir fluid is pumped through it again, in the direction of inflow.

The return permeability is an average over the length of the sample, but the damage usually sits at the end face that the fluid acted on. The sections of the sample work in series, like layers when flow crosses the bedding (the layering of the rock) (Rock permeability). So the overall coefficient is their harmonic mean (an average in which the lowest values count most), weighted by length:

Besides return permeability, we run compatibility tests. We mix the fluids with formation water and oil in different proportions at reservoir temperature. We look for a precipitate, an emulsion or a thick sludge. Tests with oil need a fresh sample whose properties have not changed in storage. We also test the rock for sensitivity to velocity, salinity, pH and acid (the table in the previous section). We find the mineral composition of the rock, and the place of the clays in the pores, by X-ray analysis, in thin sections (thin slices of rock examined under a microscope) and under a scanning electron microscope.

Before cementing, flushes and spacers (fluids pumped ahead of the cement) wash off the mudcake. Without this the cement would not bond well with the rock (Primary cementing). Without the cake, the filtrate of the cement slurry goes into the reservoir more freely. It is strongly alkaline (pH above 12) and rich in calcium. It disperses clays and dissolves part of the silica, and when it meets formation water, calcium carbonate and hydroxide come out of it. Additives limit the fluid loss of the cement slurry (how much liquid it loses into the rock) (Oilwell cements and additives), first of all for the sake of the cementing itself. So there is little filtrate, and the perforation tunnels usually pass through the zone it damages.

Two situations are more dangerous. In a fractured reservoir, the cement slurry goes into the fractures and blocks the main paths of inflow. Such reservoirs are often completed with an open hole or with an uncemented liner (a shorter casing string hung inside the one above) (Fractures and naturally fractured reservoirs). Opposite caverns (enlarged sections of the hole) the cement ring is thick, the tunnels lose length in the cement, and some of them do not reach the rock (Shaped-charge perforating).

Perforating creates a compacted zone around each tunnel, with fragments of rock and remains of the charge. How much it adds to the skin is calculated in the lesson Effect of completion on inflow. How it is cleaned by drawdown (the pressure difference that pushes fluid from the rock into the well) is covered in the lessons Shaped-charge perforating and Perforating operations: gun conveyance and procedures. For the topic of sources of damage, something else matters. When we perforate with overbalance, the fluid in the wellbore, with its solids, is the first thing to enter the fresh tunnels. So before such perforating we fill the well with clean, filtered fluid. It is even better to perforate underbalanced.

During production the damage usually builds up gradually. Productivity falls over months, often after some event: water breakthrough, a drop in pressure, a rate change. The main sources are fine particles, salts, paraffins and asphaltenes, and sand.

Fine particles (fines) are fragments of clay minerals and feldspars (common rock-forming minerals), and quartz dust. Their size is from fractions of a micrometre to tens of micrometres. They lie on the surface of the grains and in the pores. The flow pulls on them with a force that grows with velocity. Electrical and molecular forces hold them in place, and these depend on the salinity and pH of the water. While the velocity is low, the particles stay put. Above the critical velocity they are torn loose and get stuck in narrow channels, most of all near the wellbore, where the velocity is highest (fines migration).

The particles are usually wetted by water and sit in a water film. So it is the flow of water, not of oil, that moves them. While the well gives oil with no water, the particles hardly move. After water breakthrough the same liquid rate can be above the critical value. We measure the critical velocity on core, by raising the flow rate in steps until the permeability starts to fall. We then apply it to the well, using the area where the flow enters the wellbore:

If the calculation shows a danger, we bring the well up to its working rate smoothly, in steps. The particles are then carried out a little at a time, and they have no chance to collect into plugs at the tunnels. We also limit how much water the well produces, and we increase the inflow area. Clay stabilisers (chemicals that fix the particles in place) hold the particles, but their effect is usually temporary. Particles that do break loose are better carried into the well than held back in the pores. Screens and gravel packs are chosen to hold back sand and let the fines pass (Sand control methods).

Salts come out when the water in the pores or in the wellbore becomes supersaturated (holds more dissolved salt than it can keep). There are three causes. The first is a fall in pressure: carbon dioxide leaves the water, the pH rises, and calcium carbonate comes out. The second is the mixing of incompatible waters: formation water rich in barium and strontium, and injected water rich in sulfate. The third is cooling and evaporation: in gas wells, halite (rock salt) comes out of salty water. Hydrogen sulfide reacts with iron and gives iron sulfides. Salt blocks the pores near the wellbore and the perforation tunnels, and higher up it blocks the tubing, pumps and safety valves. We judge how likely a water is to leave salt deposits (scale) with the saturation index (SI):

A balance of the ions tells how much salt can come out if the mixture reaches equilibrium. Barium and sulfate leave the solution in equal amounts, $x$ mol/L each, until the product of the remaining concentrations equals $K'_{sp} = K_{sp}/(\gamma_{\text{Ba}}\gamma_{\text{SO}_4})$:

The place where the water mixes decides where the salt comes out. In the reservoir, the injected water pushes the formation water ahead of it as a front, and the two mix only in a narrow band that moves away from the injection well. When the water breaks through to the production well, the flows from different layers, with and without injected water, mix right at the wellbore and in the tubing. That is where the deposits grow. So we squeeze scale inhibitors into the reservoir in advance (we pump them into the rock, where they are held and released slowly). At concentrations of a few to tens of parts per million, they slow down the start and growth of crystals, and they are washed out slowly with the water. Calcium carbonate dissolves in hydrochloric acid, but barium sulfate hardly dissolves in acid at all. We remove it with chelating solutions (solutions that bind the metal ions), or mechanically, or we bypass it by re-perforating. Deposits of barium and strontium sulfates can be weakly radioactive, and they are handled under the radiation safety rules. The chemistry of produced water and its treatment are covered in the lesson Produced water: composition, treatment and disposal.

Paraffins are dissolved in the oil at reservoir temperature. They come out as crystals when the temperature falls below the wax appearance temperature (WAT). This usually happens in the tubing and flowlines (the pipes that carry production from the wellhead to the plant). It can also happen in the reservoir near the wellbore, if that zone is cooled by injecting cold water or flushing fluids. An example is the Uzen field on the Mangyshlak peninsula. Its oil is rich in paraffin (according to studies of the 2020s, about 17–19% paraffin by mass). Decades of cold-water injection have lowered the reservoir temperature, and now the wax appearance temperature is comparable with the present reservoir temperature. So paraffin can come out already in the reservoir and the near-wellbore zone. Paraffin is removed with hot oil and solvents, and it is prevented by keeping the temperature up and by inhibitors.

Asphaltenes are heavy, polar components of the oil. They stay in the oil as a colloidal suspension (very fine particles spread through the liquid) while resins keep them stable. When the pressure falls, but is still above the bubble point pressure (the pressure at which gas starts to come out of the oil), the oil expands, its power to dissolve falls, and the suspension loses its stability. This is strongest near the bubble point pressure. Below it, gas leaves the oil, and the oil again becomes a better solvent. Asphaltenes that have come out dissolve poorly, and only in aromatic solvents (such as toluene). So it is easier to prevent them: keep the pressure above the level at which they start to come out, and use inhibitors. Acid, especially acid with ferric iron (iron in the +3 state), forms a sludge with such oil, and the sludge is almost impossible to remove (Acid systems and treatment design).

Sand is carried out by the flow when the stresses at the wall of the wellbore and of the tunnels exceed the strength of the rock. When and why this happens is covered in the lesson Sand production: types, prediction and cost of the problem. As the reservoir is depleted, the effective stress (the stress that the rock grains carry) rises throughout the reservoir. In rocks that are sensitive to stress, the permeability falls and fractures close (Rock compressibility and the effect of stress on core properties). Gas coming out of solution near the wellbore below the bubble point pressure, and condensate dropping out, also lower productivity. But these are not damage to the rock. They are a component of skin that depends on the operating regime (Skin factor).

Bacteria enter the well with injected fluids. Their slime and waste products plug the pores. Sulfate-reducing bacteria produce hydrogen sulfide. It causes corrosion, and it reacts with iron to form a precipitate of iron sulfide. The defence is biocides (chemicals that kill bacteria) in all injected fluids and clean equipment.

An injection well takes tens and hundreds of thousands of cubic metres of water a year. That is far more than any fluid pumped into a production well. So even a small content of suspended solids (particles of sand and clay, corrosion products, drops of oil, bacteria) slowly builds a cake on the walls of the tunnels and plugs the pores near the wellbore. Then the injectivity (how much water the well takes per unit of pressure) falls. Particles larger than about a third of the pore throats build an external cake. Smaller particles go deeper (Formation damage and damage skin).

Produced water that is returned to the reservoir adds oil and fine suspended solids, and the mixing of waters from different sources adds salts. Fresh water in a clayey reservoir lowers the salinity in the pores below the critical value, and clay particles detach and migrate (see the advanced section). Cold water cools the near-wellbore zone. In a high-paraffin oil this threatens paraffin deposits. But it also lowers the stresses in the rock, and during injection fractures often open. These fractures raise the injectivity and make the well less sensitive to suspended solids. The requirements for water quality and its treatment are covered in the lesson Water injection systems.

Before a workover we usually kill the well. We fill it with kill fluid, whose column balances the reservoir pressure with a margin. Part of the fluid goes into the reservoir, and with it goes everything that was in it: particles from unwashed tanks and lines, rust and mill scale (flakes of oxide from the steel) from old pipes, thread grease, remains of drilling mud and cement slurry, and thickeners. Work above the reservoir brings an especially large amount of dirt: drilling out cement and packers (seals that close the gap around the tubing), scraping the casing, and milling (cutting away metal). If the brine is incompatible with the formation water or the clays, deposits and swelling add to the plugging, and in gas reservoirs a water block adds too.

The sign of such damage is productivity after the workover that is lower than before it, at the same reservoir pressure. It can be noticed already during the workover. If the daily loss of fluid into the reservoir drops sharply after some operation, the tunnels have most likely become blocked.

• Clean fluids. Filtered brines with no solids. Clean tanks, lines and pipes. We check the quality by the content of suspended solids and by turbidity (cloudiness). On the threads of pipes that go down to the reservoir, we use a minimum of grease.
• Pills instead of weighting material. If the losses are large, we place pills (small volumes of special fluid) with bridging agents of the right size, soluble in acid or water (calcium carbonate, salt), or viscous pills with a breaker that destroys the thickener.
• Compatible brines. Solutions of potassium or ammonium chloride for clayey reservoirs. Calcium and zinc brines are checked for compatibility with the sulfates, carbonates and hydrogen sulfide of the reservoir fluids.
• Work without killing. Where possible, we work under pressure: through coiled tubing (a continuous flexible pipe), on wireline (a cable), or with a snubbing unit (equipment that runs pipe into a well under pressure). Or we shut off the reservoir with a plug in the tail pipe of the tubing (its lowest section).
• Clean pipes. Before treatments are pumped through old tubing, the pipes are washed with acid, with the returns taken to the surface. Otherwise the fluid will drive rust and deposits from the walls into the reservoir.

The signs of damage are productivity below what we expect, a large skin after the pseudo-skins are subtracted, and intervals that do not work. They are listed in the lesson Formation damage and damage skin. To choose a cure, we need the next step: to understand which operation and which mechanism created the damage.

The diagnosis almost always has several sources, and we test it by experiment: laboratory tests with the fluids that were pumped into the well, and the result of the first treatment. A failed treatment is information too. If acid did not help, the damage was perhaps not the kind that it was designed for (Acid treatments: principle, economics and candidate selection).