Bottomhole pressure

A blowout, which is the continuous flow of oil or gas to the surface through the annulus, is the result of a lack of sufficient bottomhole pressure from the column of circulating fluid and proper well head equipment. 

Stable Foam. When a well is drilled with stable foam as the drilling fluid, there is a back pressure valve at the blooey line. The back pressure valve allows for a continuous column of foam in the annulus while drilling operations are under way. Thus, while drilling, this foam column can have significant bottom-hole pressure. This bottomhole pressure can be sufficient to counter formation pore pressure and thus control potential production fluid flow into the well annulus. 

Aerated Mud. In aerated mud drilling operations, the drilling mud is injected with compressed air to lighten the mud. Therefore, at the bottom of the well in the annulus, the bottomhole pressure for an aerated mud will be less than that of the mud without aeration. However, an aerated mud drilling operation will have very significant bottomhole pressure capabilities and can easily be used to control potential production fluid flow into the well annulus. 

The number of fixed volumetric flowrate compressors is selected such that the necessary minimum air volumetric flowrate is exceeded. The air volumetric flowrate that the compressors produce is shown as the real air volumetric flowrate. This real air volumetric flowrate, (actual cfm) is used to calculate the bottomhole pressure. Bottomhole pressure, (Ib/fi abs) is determined by... 

Knowing the bottomhole pressure, the number of bit orifice openings and the inside diameter of these openings, the pressure inside the drill pipe just above the bit and the surface injection pressure can be found. 

Calculate the expected reduction in bottomhole pressure and pit gain for the data as given below ... 

The guiding principle of all these techniques is that bottomhole pressure is held constant and slightly above the formation pressure at any stage of the process. To choose the most suitable technique one ought to consider (a) complexity of the method, (b) drilling crew experience and training, (c) maximum expected surface and borehole pressures and (d) time needed to reestablish pressure overbalance and resume normal drilling operations. 

Step 1. The well is circulated at half the normal pump speed while keeping the drillpipe pressure constant (see Figure 4-352a). This is accomplished by adjusting the choke on the mud line so that the bottomhole pressure is constant and above the formation fluid pressure. To maintain a constant bottomhole pressure the formation fluid is allowed to expand, which usually results in a noticeable increase in casing pressure. This step is completed when the formation fluid is out of the hole. At this time casing pressure should be equal to the initial SIDPP if the well could be shut in. 

Step 2. When the formation fluid is out of the hole, a kill mud is circulated down the drillpipe. To obtain constant bottomhole pressure, the casing pressure is kept constant (see Figure 4-352b) while the drillpipe pressure drops. Once the kill mud reaches the bottom of the hole the control moves back to the drillpipe side. The drillpipe pressure is maintained constant (almost constant) while the new mud fills the annulus. 

This method can be used if the kick is taken during tripping up the hole with the bit far from the bottom of the hole. Again the constant bottomhole pressure principle is used to control the situation. 

It is suggested to evaluate the burst load based on the internal pressure expected, reduced by the external pressure of the drilling fluid outside the string. Internal pressure is based on the expected bottomhole pressure of the next string with the hole being evacuated from drilling fluid up to a minimum of 50%. In exploratory wells, a reasonable assumption of expected formation pore pressure gradient is required. 

Matrix acidizing treatments are more often performed, nowadays, with sensors and data acquisition systems continuously recording the surface pressure and rate histories. According to a recently proposed methodology (15), these records can be used to compute downhole rate and pressure evolutions. The bottomhole pressure history is then compared to the theoretical response of an equivalent reservoir wherein a non-reactive fluid would have been injected according to an identical rate schedule. Following this method, the difference between both theoretical and actual pressure responses originates from the evolution of the skin of the true reservoir under the influence of the acid attack. Equation 1 is then used to derive the skin decrease from this pressure difference. 

Then, 11 m3 (70 barrels) of 15 /, HC1 were pumped downhole through a coil tubing. The bottomhole pressure history is in this case precisely derived from surface data, since the latter are collected in the open annular space between the coil tubing and the casing. No computation of friction pressure drops all along the injection string is needed, which removes a major source of errors in the derivation of bottomhole data. The bottomhole pressure is just equal to the sum of the surface... 

Figure 2 Surface rate and bottomhole pressure evolutions during treatment of Well A.

As a result of an increased flow resistance, foam injection is often accompanied by an increase in the injection-well bottomhole pressure (BHP). Temperature surveys at injection, production, and observation wells indicate whether foam is successfully diverting steam. By minimizing gravity override, a successful foam application increases the temperature... 

Field Monitoring. The interpretation of bottomhole pressure has become an important factor in the stimulation of oil and gas wells since the work of Nolte and Smith was published (47). 

Bottomhole pressures can be recorded with mechanical devices such... 

Implementation of an on-site computer control unit eliminates the need for mechanical systems, and enables real-time computation of bottomhole pressures. Monitoring techniques and pressure calculation methods vary extensively throughout the service industry. However, the measurable parameters such as surface treating pressure, liquid and gas injection rates, proppant concentration, and slurry temperature are the parameters that must be used to determine the bottomhole pressures. 

Determination of bottomhole pressures for conventional fracture fluids such as gelled oil or water are relatively simple compared to foam bottomhole pressure calculations. However, when compressible fluids such as foams are used, more rigorous calculations are required to determine bottomhole pressures. Foam density, foam quality, and injection rates are functions of temperature and pressure. 

The use of the bottomhole treating pressures enables the fracture parameters to be calculated more accurately. As well, the continuous or dispersed phases can be altered as the treatment progresses in order to achieve maximum fracture propagation. The more accurate the prediction of the bottomhole pressures, the more reliable the data can be to create the best possible stimulation treatment. 

Recent gains using foamed fluids result from the improvements in on-site quality control. More accurate monitoring equipment, the ability to adjust input parameters during the treatment, and real-time calculations of bottomhole pressures and qualities enable more accurate rheology calculations, and thus allow for high-efficiency stimulations and improved productivity gains. 

The bottomhole pressure of injection wells was determined according to the known barometric formula. However, for the gas wells a correction was made for the increase in gas density. The steam density was calculated to be 20-30% higher on account of the moisture content, and gas density was assumed to equal 0.7 of air density. Inasmuch as the pressure changes in the production-observation wells were not significant, the effects that the injection wells exerted mutually among themselves could be ignored. In other words, it was assumed that all injection wells operated independently of one another. Before the pressure field map was constructed, all pressures measured in the production-observation wells were brought up to the moment at which steam injection was discontinued. Visual extrapolation was used for that puipose. 

Example 5,6—Estimation of Pressure Drop Through a Reservoir. A polymer flood is being designed that uses 1,000 ppm xan-than biopolymer. The polymer solution will be injected into a sandstone reservoir at a rate of 10 B/D-ft. The permeability of the reservoir is 200 md, porosity is 0.19, and thickness is 50 ft. Initial oil saturation is 0.70, and ROS is 0.30. A five-spot pattern is planned on 10-acre spacing. Radius of the injection well is 3.25 in., and there is no wellbore damage. At the beginning of the polymer flood, the reservoir is at interstitial water saturation and contains a crude oil with a viscosity of 1.0 cp at reservoir temperature and pressure. For this example, the displacement process is considered piston-like so that a sharp displacement front will form between the displaced oil and the injected polymer solution. Polymer retention and inaccessible PV are ne ected. Determine the bottomhole pressure (BHP) in the injection well when 1,000 bbl of polymer solution have been injected. The average reservoir pressure at the effective radius of the five-spot pattern is 400 psi. 

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