Flows wellbore

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

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... 

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. 

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 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. 

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. 

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. 

The rate of flow that would be produced by a well if the only pressure against the face of the producing formation in the wellbore equals atmospheric pressure. 

Movement of fluid between the wellbore and shale, which is limited to flow from the wellbore into the shale... 

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. 

The drill-in fluids are typically composed of either starch or cellulose polymers, xanthan polymer, and sized calcium carbonate or salt particulates. Insufficient degradation of the filter-cakes resulting from even these clean drill-in fluids can significantly impede the flow capacity at the wellbore wall. Partially dehydrated, gelled drilling fluid and filter-cake must be displaced from the wellbore annulus to achieve a successful primary cement job. 

Cleaning of the wellbore region through the acids and gas fi-om in situ fermentation The gas serves to push oil from dead space and dislodge dehris that plugs the pores the average pore size is increased and, as a result, the capillary pressure near the wellbore is made more favorable for the flow of oil... 

A physical model to predict the large-scale application for MEOR has been developed. This model simulates both the radial flow of fluids toward the wellbore and bacteria transport through porous media [1235]. 

Turbulent flow at reasonable pump rates aids in removal of drilling mud from surfaces (24). Downhole devices called scratchers can be installed on the casing to scrape drilling mud residues from formation surfaces. Other devices called centralizers may be attached to the casing to center it in the wellbore. 

Properly designed, the injected acid enters the flow channels of the formation and flows radially outward from the wellbore dissolving mineral fine particles in the flow channels. Minerals forming the flow channel walls also react with the acids. These processes increase formation permeability near the wellbore. The end result... 

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. 

Flow in undisturbed rock normally is radial toward a site of lower pressure (the wellbore). The fracture crack created by high pressure injection usually forms perpendicular to the least principle stress that exists in the rock. The induced fracture intersects and disrupts the radial flow pattern such that flow becomes linear and more direct to the well. This phenomenon has been intensively examined and discussed by authors working in the discipline of rock mechanics as applied to hydrocarbon reservoirs. Hydraulic fractures created in oil and gas wells grow mainly vertically, parallel to the wellbore as depicted in Figure 1 and extend on either side of the perforated wellbore as "wings11 (7-11). 

Flow properties of macroemulsions are different from those of non-emulsified phases 19,44). When water droplets are dispersed in a non-wetting oil phase, the relative permeability of the formation to the non-wetting phase decreases. Viscous energy must be expended to deform the emulsified water droplets so that they will pass through pore throats. If viscous forces are insufficient to overcome the capillary forces which hold the water droplet within the pore body, flow channels will become blocked with persistent, non-draining water droplets. As a result, the flow of oil to the wellbore will also be blocked. 

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... 

As an example of how the dump option might be used, consider the problem of predicting whether scale will form in the wellbore as groundwater is produced from a well (Fig. 2.10). The fluid is in equilibrium with the minerals in the formation, so the initial system contains both fluid and minerals. The dump option simulates movement of a packet of fluid from the formation into the wellbore, since the minerals in the formation are no longer available to the packet. As the packet ascends the wellbore, it cools, perhaps exsolves gas as it moves toward lower pressure, and leaves behind any scale produced. The reaction model, then, is a polythermal, sliding-fugacity, and flow-through path combined with the dump option. 

With the dump command, we cause the program to discard the minerals present in the initial system before beginning the reaction path. In this way, we simulate the separation of the fluid from reservoir minerals as it flows into the wellbore. The precip = off command prevents the program from allowing minerals to precipitate as the fluid cools. In practice, samples are acidified immediately after they have been sampled and their pH determined. Preservation by this procedure helps to prevent solutes from precipitating, which would alter the fluid s composition before it is analyzed. 

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