Wellbores

An important safety feature on every modern rig is the blowout preventer (BOP). As discussed earlier on, one of the purposes of the drilling mud is to provide a hydrostatic head of fluid to counterbalance the pore pressure of fluids in permeable formations. However, for a variety of reasons (see section 3.6 Drilling Problems ) the well may kick , i.e. formation fluids may enter the wellbore, upsetting the balance of the system, pushing mud out of the hole, and exposing the upper part of the hole and equipment to the higher pressures of the deep subsurface. If left uncontrolled, this can lead to a blowout, a situation where formation fluids flow to the surface in an uncontrolled manner. 

Similarly, when drilling into an underpressured formation, the mud weight must be reduced to avoid excessive losses into the formation. If the rate of loss is greater than the rate at which mud can be made up, then the level of fluid in the wellbore will drop and there is a risk of influx from the normally pressured overlying formations. Again, it may be necessary to set a casing before drilling into underpressures. 

Formation permeability around the wellbore can be measured directly on core samples from the reservoir or from well testing (see Section 8.4), or indirectly (estimated) from logs. 

The methods discussed above only give an indication of permeability near the wellbore. Reservoir permeability is usually estimated from production tests and is described in Section 9.4. 

This section will consider the behaviour of the reservoir fluids in the bulk of the reservoir, away from the wells, to describe what controls the displacement of fluids towards the wells. Understanding this behaviour is important when estimating the recovery factor for hydrocarbons, and the production forecast for both hydrocarbons and water. In Section 9.0, the behaviour of fluid flow at the wellbore will be considered this will influence the number of wells required for development, and the positioning of the wells. 

Introduction and Commercial Application Section 8.0 considered the dynamic behaviour in the reservoir, away from the influence of the wells. However, when the fluid flow comes under the influence of the pressure drop near the wellbore, the displacement may be altered by the local pressure distribution, giving rise to coning or cusping. These effects may encourage the production of unwanted fluids (e.g. water or gas instead of oil), and must be understood so that their negative input can be minimised. 

There will be some uncertainty as to the well initials, since the exploration and appraisal wells may not have been completed optimally, and their locations may not be representative of the whole of the field. A range of well initials should therefore be used to generate a range of number of wells required. The individual well performance will depend upon the fluid flow near the wellbore, the type of well (vertical, deviated or horizontal), the completion type and any artificial lift techniques used. These factors will be considered in this section. 

The pressure drop around the wellbore of a vertical producing well is described in the simplest case by the following profile of fluid pressure against radial distance from the well. 

The difference between the flowing wellbore pressure (P, ) and the average reservoir pressure reservoir pressure (P) is the pressure drawdown (AP q). 

The flowrate of oil into the wellbore is also influenced by the reservoir properties of permeability (k) and reservoir thickness (h), by the oil properties viscosity (p) and formation volume factor (BJ and by any change in the resistance to flow near the wellbore which is represented by the dimensionless term called skin (S). For semisteady state f/owbehaviour (when the effect of the producing well is seen at all boundaries of the reservoir) the radial inflow for oil into a vertical wellbore is represented by the equation ... 

When the radial flow of fluid towards the wellbore comes under the localised influence of the well, the shape of the interface between two fluids may be altered. The following diagrams show the phenomena of coning and cuspingoi water, as water is displacing oil towards the well. 

The previous sections have considered the flow of fluid to the wellbore. The productivity index (PI) indicates that as the flowing wellbore pressure (Pwf) reduces, so the drawdown increases and the rate of fluid flow to the well increases. Recall... 

Having reached the wellbore, the fluid must now flow up the tubing to the wellhead, through the choke, flowline, separator facilities and then to the export or storage point each step involves overcoming some pressure drop. 

The purpose of the well completion is to provide a safe conduit for fluid flow from the reservoir to the flowline. The perforations in the casing are typically achieved by running a perforating gun into the well on electrical wireline. The gun is loaded with a charge which, when detonated, fires a high velocity jet through the casing and on into the formation for a distance of around 15-30 cm. In this way communication between the wellbore and the reservoir is established. Wells are commonly perforated after the completion has been installed and pressure tested. 

In high permeability reservoirs, wells may produce dry oil for a limited time following a shut-in period, during which gravity forces have segregated oil and water near the wellbore. In fields with more production potential than production capacity, wells can be alternately produced and shut in (intermittentproduction) to reduce the field water cut. This may still be an attractive option at reduced rates very late in field life, if redundant facilities can be decommissioned to reduce operating costs. 

A variety of methods have been devised to stabilize shales. The most successful method uses an oil or synthetic mud that avoids direct contact between the shale and the emulsified water. However, preventing direct contact does not prevent water uptake by the shale, because the organic phase forms a semipermeable membrane on the surface of the wellbore between the emulsified water in the mud and the water in the shale. Depending on the activity of the water, it can be drawn into the shale (activity lower in the shale) or into the mud (activity higher in the shale) (95—97). This osmotic effect is favorable when water is drawn out of the shale thus the aqueous phase of the oil or synthetic mud is maintained at a low water activity by a dding a salt, either sodium chloride or more commonly, calcium chloride. The salt concentration is carried somewhat above the concentration required to balance the water activity in the shale to ensure water movement into the mud. 

Oil reservoirs are layers of porous sandstone or carbonate rock, usually sedimentary. Impermeable rock layers, usually shales, and faults trap the oil in the reservoir. The oil exists in microscopic pores in rock. Various gases and water also occupy rock pores and are often in contact with the oil. These pores are intercoimected with a compHcated network of microscopic flow channels. The weight of ovedaying rock layers places these duids under pressure. When a well penetrates the rock formation, this pressure drives the duids into the wellbore. The dow channel size, wettabiUty of dow channel rock surfaces, oil viscosity, and other properties of the cmde oil determine the rate of this primary oil production. 

As reservoir pressure is reduced by oil production, additional recovery mechanisms may operate. One such mechanism is natural water drive. Water from an adjacent more highly pressured formation is forced into the oil-bearing formation by the pressure differential between the formations. Another mechanism is gas drive. Expansion of a gas cap above the oil as oil pressure declines can also drive additional oil to the wellbore. Produced gas may be reinjected to maintain gas cap pressure as is done on the Alaskan North Slope. Additional oil may also be produced by compaction of the reservoir rock as oil production reduces reservoir pressure. 

As the natural pressures in the reservoir decrease, oil production declines. The oil well may then be placed on-pump to maintain production at economic levels. The pump draws oil to the surface and lowers the height of the fluid column ia the wellbore. The pressure of a column of fluid can decrease the rate of fluid entry into the wellbore. 

Injection Well Considerations. Eluid injection rate can have a significant effect on oil recovery economics. Elow is radial from the wellbore into the reservoir. Thus the region near the injection wellbore acts as a choke for the entire reservoir. 

Precipitate formation can occur upon contact of iajection water ions and counterions ia formation fluids. Soflds initially preseat ia the iajectioa fluid, bacterial corrosioa products, and corrosion products from metal surfaces ia the iajectioa system can all reduce near-weUbore permeability. Injectivity may also be reduced by bacterial slime that can grow on polymer deposits left ia the wellbore and adjacent rock. Strong oxidising agents such as hydrogen peroxide, sodium perborate, and occasionally sodium hypochlorite can be used to remove these bacterial deposits (16—18). 

The mud contamination with chlorides results from salt intrusion. Salt can enter and contaminate the mud system when salt formations are drilled and when saline formation water enters the wellbore. 

The wellbore, drill string and drilling fluid data from the previous example are used. Casing depth is 4,000 ft. Assuming a drill pipe length of 5,000 ft and a drill collar length of 500 ft, find the friction pressure losses. 

Solids Injector. This is used to inject hole-drying powder into the wellbore to dry water seeping into the borehole from water-bearing formations. 

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