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Reservoir pressure and temperature
The practice of using bottomhole pressure measurements to improve oil and gas production and solve problems of reservoir engineering began around 1930. Initially, pressures were calculated using fluid levels; a later method was to inject gas into the tubing until the pressure became constant. The earliest bottomhole pressure measurements were made with one-time-reading pressure bombs and maximum-indicating or maximum-recording pressure gauges that lacked the accuracy, reliability, or durability of present-day technology.
The varied uses of bottomhole pressure and temperature measurements have increased in scope during the past two decades as instrumentation technologies have produced more reliable and accurate tools. These advances have made more applications possible, including multilayer reservoirs, horizontal wells, interference testing, and drawdown test interpretation.
- 1 Reservoir pressure
- 2 Reservoir temperature
- 3 Measurement of reservoir pressure and temperature
- 4 References
- 5 Noteworthy papers in OnePetro
- 6 External links
- 7 See also
The measurement commonly referred to as "bottomhole pressure" is a measurement of the fluid pressure in a porous reservoir. The reservoir pore-fluid pressure is a fraction of the overburden pressure that is supported by the fluid system. The other portion is supported by the rock and generates the in-situ rock stress. The overburden pressure is created by the weight of the rocks composing the lithostatic column at the point of observation. Hence, the difference between the overburden pressure and the vertical rock stress can approximate the pore pressure.
At original, or virgin, conditions, the vertical pressure profile reflects the distribution of fluids in the reservoir and may also indicate compartmentalization resulting from fluid flow barriers. Within any reservoir compartment, the pressure gradient reflects the density of the continuous fluid phase in the reservoir, hence the position of fluid contacts. Fig.1 illustrates a typical pressure profile showing gas-, oil-, and water-bearing intervals of a reservoir at initial conditions.
In a developed reservoir, differential depletion of lithostatic layers with various permeabilities and the movement of fluid contacts can change the pressure profile. Monitoring the static pressures vs. time in developed reservoirs is a crucial tool for reservoir management.
Pressure distribution in the reservoir during fluid flow
The fluid flow article explains the factors that govern the flow of fluids through porous media for steady-state, pseudosteady-state, and transient flow conditions.
Steady-state flow is characterized by simultaneous constant pressure and flow rate. From the equation for steady-state radial flow,
the pressure profile away from a producing well can be calculated. A typical result is shown in Fig. 2.
Pseudosteady-state flow behavior is observed when a well reaches stabilized production from a limited drainage volume. For constant-rate production under pseudosteady-state conditions, the difference between the flowing wellbore pressure and the average reservoir pressure in the drainage volume is constant, and the pressure drawdown is a linear function of time. The late-time buildup pressure will level off to the average reservoir pressure if the buildup duration is sufficiently long. Pressure depletion occurs with continued pseudosteady-state production.
Transient flow is most often modeled with the radial diffusivity equation, which allows modeling pressure vs. time and pressure vs. distance from an observation point (typically, a well).
At a sufficiently large time, the pressure disturbance anywhere in the reservoir is proportional to the logarithm of the inverse square of the radius away from the origin of the disturbance. Thus, the magnitude of the disturbance is maximum near its origin (the wellbore) and rapidly terminates away from the wellbore. Because the pressure wave is affected by the reservoir fluid transmissibility, kh/μ, higher transmissibility results in smaller pressure differentials and vice versa. This effect explains why high-resolution pressure gauges are necessary to measure meaningful pressure differentials in reservoirs with high transmissibility. The radius of influence of a pressure disturbance is proportional to the square root of time. This is why the well testing time necessary to observe distant boundaries becomes prohibitively expensive, particularly in low-productivity reservoirs.
The variations of pressure as a function of time, which can be formulated by solving the radial diffusivity equation for specific cases, have given rise to well-testing applications.
Reservoir temperature is governed primarily by the reservoir’s proximity to the earth’s mantle, and by the relative heat exchange capacities and thermal conductivities of the formations forming the lithostatic sequence that includes the reservoir.
The geothermal gradient resulting from the heat-exchange process varies from basin to basin, but within a specific area the variations are small. In most hydrocarbon-producing areas, the gradient is usually in the range of 0.6 to 1.6°F per 100 ft of depth increase (Fig. 3). Areas where the earth’s crust is thinner than average, such as volcanic and geothermal areas, have much higher gradients. In thin-crust areas the gradient change averages 4°F per 100 ft of depth increase. Local temperature gradients at depth have been reported as high as 10°F per 100 ft approaching singularities (e.g., major faults, areas of tectonic movement) in the earth’s crust in geothermal areas.
To determine a precise geothermal gradient, the selected well must be shut in, without disturbance, for a period of time sufficient to let conduction effects equilibrate the temperatures. The temperature survey should be conducted from surface to bottom on the first descent into the well and at a slow speed (ideally, no more than 30 ft/min to accommodate the thermal inertia of the sensor). This procedure is necessary because the passage of the thermometer alters the static gradient. Even if a precise gradient is not required, following the procedure is still recommended for running temperature surveys in wells (shut-in, injecting, or flowing). Anomalies present during the first descent—whether observed or not—may disappear on subsequent surveys after disruption of the initial thermal equilibrium.
The virgin reservoir temperature may be determined when drilling initial exploration and appraisal wells by using the maximum temperatures recorded on successive logging runs or wireline sampling operations. The technique calls for plotting Tbh vs. (tk + Δtc)/Δtc on a linear scale.
These data are interpreted in Horner analysis fashion by drawing a straight line through the data points and extrapolating to the reservoir temperature at (tk + Δtc)/Δtc = 1, which corresponds to infinite shut-in time. Even though this approach is not mathematically rigorous, it provides reliable estimates of the static temperature when short circulation times are assumed. This technique is especially applicable to regions with high geothermal gradients, where the temperatures recorded at the time of logging runs can be significantly lower than the static temperature.
Measurement of reservoir pressure and temperature
Many techniques exist for obtaining bottomhole reservoir pressure and temperature. A variety of logging techniques may be used. See Acquiring bottomhole pressure and temperature data for more information. The techniques described below are emerging techniques or special considerations.
Optical fiber measurement of pressure and temperature
Several systems are being developed to provide pressure and temperature measurements distributed over the length of an optical fiber that is permanently deployed in the completion. An advantage of fiber optic technology is that the sensors have no electronic components at depth, so they tend to be more reliable. Furthermore, optical sensors are:
- Immune to shock
- Not prone to electromagnetic interference
- Operable at high temperatures
Fiber optic technology is based on exposing the fiber to periodic ultraviolet (UV) light patterns that induce a "grating" on it. Pressure and temperature variations change the reflection wavelength of the gratings and can be decoded with respect to the fixed, incipient operating wavelength. The system is self-referencing.
Every point distributed along the length of the fiber has the potential to generate a different temperature measurement. The advantages are measurement of a permanent temperature gradient over the length of the fiber and the ability to select specific measurement points. Single-point and distributed temperature sensors have been reported to operate successfully in steamflood wells up to 575°F. In one reported case, temperature measurements taken along a horizontal wellbore at different times showed steamchests, water breakthrough, crossflow, and flow behind pipe.
Pressure is measured by sensors located at discrete, fixed points along the fiber. At the sensors, the fiber is cut, and its ends are placed face-to-face in a proximal arrangement. The face-to-face spacing is measured by successive reflections of the light wave. Changes in the value of the spacing reflect the environmental pressure around the fiber at that point. The self-referencing technique uses the distributed temperature measurement for suitable corrections.
Measurement of pressure and temperature at wellhead
Although the focus of this article is bottomhole measurements, it is worthwhile to mention a few interesting points about the environments of surface and subsea measurements.
Surface acquisition of downhole data
Current specifications of surface acquisition systems, sensors, umbilicals, and piping commonly used in the industry are 0 psi and –40°F for the lower range of pressures and temperatures, respectively. The temperature specification in particular presents no obstacle to testing operations in extremely cold areas, such as the Arctic and similar cold-weather territories.
Subsea acquisition of pressure and temperature
Pressure and temperature measurements are sometimes required at the subsea tree level. The measurements are mainly used to monitor the operating conditions of the landing string near the ocean floor. Applications include ensuring that the maximum temperature rating of the elastomers in the blowout preventer (BOP) is not exceeded, and providing data to help prevent hydrate formation during deep-sea cleanup and well testing operations.
- Dowdle, W.L. and Cobb, W.M. 1975. Static Formation Temperature From Well Logs - An Empirical Method. J Pet Technol 27 (11): 1326-1330. SPE-5036-PA. http://dx.doi.org/10.2118/5036-PA
Noteworthy papers in OnePetro
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