Managing Risk and Reducing Damage From Well Shut-Ins

A technical synopsis of major considerations for unconventional wells facing prolonged shut-ins. The review includes deciding factors for kill fluid selection and risks of incompatible fluid mixing.

A wellhead in the Permian Basin. Source: ConocoPhillips


Shutting in wells for any reason has a risk of diminished flow when the wells are restarted. The entire flow system from the formation to the off-take mechanism should be considered. Some systems, such as high-pressure dry gas, may accept a simple valve closure as a shut-in without much restart risk, but other wells may be much more sensitive. The restart risk rises when produced fluids in the wellbore separate and gas pressure builds sufficiently to push the wellbore liquids back into the producing formations. Depressuring a static liquid column in the wellbore can result in organic precipitates, sludges, and emulsions with components such as CO2 and iron-rich waters acting as catalysts for creating or stabilizing the emulsion products. These reactions are problematic when confined to a static column, but the risk of creating flow-blocking mechanisms rises sharply if the liquids enter the matrix and mix with connate fluids. The following discussion focuses on well shut in and startup results encountered in several basins around the world, both onshore and offshore, and highlights methods of estimating risk based on well and produced fluid characteristics.


Some well-flow conditions raise the risk of blockage:

  • Pressure—Pressure depletion in a reservoir substantially increases damage risk. Low-pressure wells are highly susceptible to relative permeability-blocking effects. Water-and-oil blockage in the formation is a well-known problem and is often seen in the efforts of bringing a low-pressure well back after a workover. Relative permeability problems are a common blocking mechanism and easily prevented and treated with chemicals specifically selected for the job.
  • Crossflow—Wells with multiple producing layers or even widely varying permeability are the first warning sign of problems to come when a well is shut in. Permeability variances within the producing set of inflow points (formation layers flowing into the wellbore), create groups of lower-pressure, higher-permeability zones and groups of higher-pressure, lower-permeability zones. During production, the flowing bottomhole pressure will usually be low enough to maintain flow from all zones, but when flow is stopped, crossflow from high pressure to low pressure may start. Mixing of gases, oils, and waters from different zones can create many problems, some of which are extremely difficult to remove. 
  • Multiple source rocks—Different sources may feed into layers within a single reservoir and some wells penetrate and produce from multiple layers. Examples of up to seven shale source rock contributions have been identified in some Permian Basin wells. Mixing of asphaltic and paraffinic oils, common in many basins, may create downhole and in-situ organic precipitates that can partly or totally block small and large flow passages within the rock fabric. Paraffins may be “chilled” into precipitating by cooler fluids falling back and mixing with oil in the well or the near wellbore. Asphaltenes, however, are another matter; solid asphaltic masses in the wellbore or in the formation can be triggered by fluids of different layers mixing in a single zone. Additional trigger mechanisms for asphaltene precipitation are influx of water with high iron contents, shifts in the pH of fluid from a specific rock layer, or outgassed oils missing important short-chain and aromatic hydrocarbons that flashed off during initial production.
  • Variance in connate water—Multiple produced-water sources within a well may create inorganic scales, and remixing waters that flashed off CO2 during production can concentrate waters that are super saturated with calcium and iron. Incompatible water sources may bring barium and calcium together with other sulfate-rich waters—resulting in scales that may be difficult to remove, especially when mixing and precipitates occur within the pores of the rock. Clay interactions with mixed waters are possible, and damage from clay swelling or migration may be difficult to remove.
  • Ductile and unstable formations (e.g., unconsolidated sands) are difficult to produce under the best conditions. Production from these wells is easily damaged by changes in flowing conditions. Initiation of flow from “soft” or ductile formations is best achieved by controlled drawdown and flow that is as steady as possible. Changes in flowing conditions may produce a spike in the flow of solids before reaching a semi-steady state of flowing equilibrium. Shutting in these wells must be done carefully, and restarts must be initiated in a very controlled manner.
  • Hydrate formations are usually well known for a specific development and will not be covered here.
  • High-rate water-injection wells, particularly in soft or poorly consolidated formations, are subject to backflow from a short-lived but damaging over-pressured event. These problems, often mislabeled as water-hammer events, occur where high-rate water injection is stopped suddenly, allowing momentum of the injected water to pressure up near the wellbore, temporarily creating a lower pressure in the tubing before pressure is equalized by flowing back into the well. This produces a backflow surge from the formation that can carry water and formation sand into the well and can fill hundreds of feet of tubing with sand.
  • Corrosion—Well integrity impacts from a corrosion perspective should also be considered when planning on shutting in wells for an extended time. Hence, well preservation is critical, and factors such as anticipated shut-in durations and production conditions should be taken into account. This includes a good understanding of potential corrosion rates by adequately accounting for critical factors such as fluid pH, CO2/H2S levels, chlorides, and other fluid and material characteristics.
  • Surface Facilities—Certain gathering systems and facilities may be impacted when shutting in wells. This may include completely shutting down and isolating flowlines, or flowline and pipeline segments, as well as various gathering facilities. In some instances, this may result in reduced throughput from certain gathering stations, which may require adjusting of various key items including chemical treatment rates and other factors which may help with further reducing OPEX. 

Specific Cases of Shut-in Damage

  1. Remaining reservoir pressure at shut-in is a first consideration. Higher pressure is always better for bringing wells back on, assuming a single inflow source or even multiple sources if pressures are all the same. Wells with reservoir pressures below about 0.3 psi/ft are at higher risk of not returning to production. Pressures below about 0.2 psi/ft are nearly always critical problems, usually creating slow or no recovery.
  2. Multiple inflow sources with different pressures will result in crossflow during pressure buildup during a shut-in. High-pressure, low-permeability zones will flow into low-pressure, high-permeability zones. At minimum, this crossflow will create relative permeability effects. Relative permeability effects may be minor in the high-permeability zone and much more serious in a low-permeability zone where capillary blocking effects dominate flow. 
  3. Lower permeability can be a problem, depending on the type of fluid in the rocks and the permeabilities of the formation. Capillary blocking pressure is the force that must be overcome to flow fluid through pores of the rock. The blocking pressure goes up sharply as permeability (in matrix or natural fractures) goes down. At low permeability, (usually less than about 10 to 500 microdarcies), the reservoir pressures to initiate flow may exceed 1000 psi.  
  4. If the fluids in different zones are incompatible, water-precipitated scales, and/or organic precipitates such as asphaltenes or paraffin, are possible. Knowledge of fluid compositions and incompatibilities is critical. To prevent a scale or organic precipitate problem, inhibitors or stabilizers can be injected or dropped into the well before shut-in. Scale inhibitors are generally phosphate esters (nonadsorbing), phosphonate materials that precipitate and slowly dissolve, or polymer-based (various reactions). Oils with high asphaltic content present a particularly difficult problem. Asphaltic platelets (at angstrom size) are suspended in oils, but when oils from a different source are mixed, the asphaltene platelets will agglomerate and the resultant “precipitate” is very resistant to removal. We learned to never use asphaltic oils as kill fluids and to take care with mixing oils from different layers in a single well—we saw this in black oils (C10 to C20+) from Canada, west Texas, and Argentina. These wells need a few barrels of xylene before shut-in to minimize the problem.
  5. Formation mineralogy often includes clay or other minerals that may absorb or adsorb water. Shales, mudstones, and higher-clay-content rocks are most vulnerable. There are five major factors: clay type, clay location, permeability, water composition, and time of contact. While smectite is normally considered to be the worst-acting clay for blocking pore passages, some other forms such as pore linings of smectite, illite/smectite, fibrous illite, and a few other minerals may present a problem. Pore-space clay growths (authogenic) are the worst, and clay in the matrix away from the pores (detridal) is a much-reduced problem. Low-permeability rock limits the ability of water from the wellbore or other layers to reach the clays. Water compositions that are radically different from connate water in the layer will react with the clays to form a stable clay-water status. If water must be used to kill a well, the water composition must be as close as possible to the connate water. If the connate water composition is not known, use a similar total dissolved solids (TDS) to the produced water with 10% calcium chloride and 90% sodium chloride brine. Time of water contact and water loss in most wells should be minimized.   
  6. Water remaining on shale fracture faces may soften the shale structure and lead to proppant embedment and loss of flow capacity.
  7. Emulsions at depth are usually not a problem except in rare circumstances on injected chemicals that artificially stabilize emulsions. Most emulsions are created by flow energy—turbulence at the perms or energy from the lift system. Rod pumps, gas lift, and ESPs are the biggest culprits.
  8. Startup flow may be erratic with several stages of emulsions, precipitates, gels, etc. seen at the facilities as flow begins. Jetting in a well will create emulsions, but those should break quickly at the surface unless they are stabilized by particles of silica, clays, rust, ice, etc. Stabilized emulsions are more difficult to break and need some form of slow agitation (low energy) and mixing dispersing chemicals or solvents into the flow. The best ways of doing this may include injecting a mutual solvent at the wellhead and letting flow down the gathering line disperse the solvent/breaker materials.
  9. Reservoir-fluid type is an important factor, especially at higher viscosities—oil is hard to start flowing but viscous oil is even more difficult. Gas is usually easier, but gas displacement of liquids is limited by fingering as the gas slips past the oil. 
  10. Cleanup of a formation through flow via drawdown is limited by the amount of exposed wellbore—this is why vertical wells with just the thickness of the formation clean up quicker than long horizontal sections with ten to over a hundred times the formation coverage. It’s a little hard to comprehend, but flow rate per unit area is a key to cleanup, and higher formation contact limits the flow rate and the cleanup potential.
  11. At Amoco, we once experimented with shutting wells in with a high column of liquid to see if the standing fluid would damage newer wells (still high-pressured). Gas pressure percolated to the top of the casing and pressured up the well, pushing fluids back into the reservoir. Usually, the high permeability streaks get the most displaced fluid. This and crossflow may explain the longer-than-expected swab times when bringing the wells back on line.
  12. Gas wells with high pressure and very little water are the lowest risk for shut-in. Gas wells with very low pressures (<0.2 psi/ft) may require treating with a surface tension or interfacial tension reducer to remove water blocks. In Hugoton field, where reservoir pressure was less than 200 psi at depths of over 3,000 ft, killing a well was a “death sentence.” We tried pressuring up the wells with injected field gas with very poor results. Then we developed a routine treatment of injecting 3 to 10 drums of methyl alcohol with sufficient field gas to push the alcohol out at least 10 ft into the formation. The success rate was about 60 to 70% on the first treatment and perhaps 10 to 30% on the second treatment. Some wells never came back on. The lesson we learned was to use hydraulic workovers (snubbing) in these ultralow-pressure wells. Straight shut-ins were preferable to killing the well in most cases.
  13. If the fluids in different zones are incompatible, water-precipitated scales, and/or organic precipitates like asphaltenes or paraffin, are possible. Knowledge of fluid compositions and incompatibilities is critical.
  14. Fluid type is a factor, especially at higher viscosities; oil is hard to start flowing but viscous oil is even more difficult. Gas is usually easier, but gas displacement of liquids is limited by fingering as the gas slips past the oil.
  15. Lower permeability can be an issue, depending on the type of fluid in the rocks and the permeabilities of the formation. Capillary pressure is the force necessary to flow fluid through pores of the rock, at low permeability (usually less than about 10 to 500 microdarcies). The pressures to overcome capillary effects and get fluids to start flowing though these sections is in the neighborhood of 1000 psi.
  16. Cleanup of a formation through flow via drawdown is limited by the amount of exposed wellbore—this is why vertical wells with just the thickness of the formation clean up quicker than long horizontal sections with many times the formation coverage. It may be difficult to comprehend, but flow rate per unit area is a key to cleanup, and more formation contact limits the flow rate and the cleanup potential.

Gathering Systems and Facilities Integrity Assessment

Another important aspect that impacts the efficient performance of the asset’s surface facilities is the gathering system status and the particular conditions of associated production equipment. Detailed assessments should include investigating key items such as well/network routing, life of field, current field conditions, systems that will be impacted with well shut-ins, turndown requirements, chemical requirements, power requirements, and maintenance requirements, just to name a few. This should include considerations for the following:

  • Corrosion Management Program Review including identification of potential corrosion threats and mechanisms, as well as increased corrosion risk areas.
    • Chemical Treatment Management Program Review with assessment of existent inhibition program performance (i.e., corrosion inhibitors quality, treat rates) to reduce or optimize chemical treatments.
    • Inspection and Preventive Maintenance Management Program Review that may include risk-based inspection program management review and review of inspection and maintenance plans.

Existent surface facilities might be underutilized, oversized, or can be constrained at the current operating conditions. Determination of the excess capacity and the optimum way to route the produced fluids is of high importance to reduce spare or unnecessary capacity and minimize operating expenses. Several actions can be taken to accomplish this objective:

  • Gathering System and Facilities Optimization
    • Includes risk-based inspection program management review and inspection and maintenance plan review
    • Includes data-driven and model-based optimization
    • Produced fluid-routing options with an aim to minimize OPEX including:
      • Reduced chemical costs
      • Reduced power requirements
      • Reduced manpower requirements