A Joint Industry Project To Assess Circulating Temperatures in Deepwater Wells
- M. Ward (BP plc) | V. Granberry (ChevronTexaco) | G. Campos (Petrobras) | M. Rausis (Petrobras) | M. Sledz (Petrobras) | L. Weber (Unocal) | D. Guillot (Schlumberger) | I. Naziri (Schlumberger) | J. Romero (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2003
- Document Type
- Journal Paper
- 133 - 137
- 2003. Society of Petroleum Engineers
- 4.2.4 Risers, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 5.9.1 Gas Hydrates, 1.6 Drilling Operations, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2 Pipelines, Flowlines and Risers, 1.2 Wellbore Design, 1.11 Drilling Fluids and Materials, 4.3.1 Hydrates, 3 Production and Well Operations, 1.10 Drilling Equipment, 2 Well Completion, 1.6.1 Drilling Operation Management, 1.12.1 Measurement While Drilling, 1.7.6 Wellbore Pressure Management, 2.1.7 Deepwater Completions Design, 1.5 Drill Bits, 1.14 Casing and Cementing, 1.6.10 Running and Setting Casing, 1.14.3 Cement Formulation (Chemistry, Properties)
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Drilling oil wells offshore in water depths exceeding 1000 m is not uncommon in many parts of the world. These conditions present a number of challenges for successfully drilling and completing these wells. A major challenge is predicting the temperature of various fluids, such as drilling muds and cements, when they are circulated or placed in the well and during static periods. What sounds like an easy task for the majority of land or offshore wells with shallow water depths turns out to be much more difficult for deepwater wells. This is particularly caused by inverse temperature gradients across the sea and convective thermal exchanges between the sea and the fluids in the riser and/or drillpipe.
To better understand the phenomena involved, a series of temperature measurements was made as part of a joint industry project (JIP). The primary objective of these measurements was specifically to monitor the cooling effect of the sea by measuring the fluid temperature at the mudline depth. All temperature data were measured by a sensor deployed inside the bottomhole assembly (BHA) while circulating or drilling. Data were collected in the Gulf of Mexico, Brazil, Indonesia, and west Africa in an average water depth of 1200 m.
A summary of the temperature measurements is presented, and comparison is also made with the predictions of a numerical simulator. Detailed interpretation of the data gathered pinpoints the importance of correctly accounting for the exact temperature profile in the sea as well as the velocity of sea currents vs. depth.
Knowing the temperature profile in an oil well can be quite important for designing drilling operations, but this piece of information is critical for designing cementing operations, for obvious reasons. This is even more important in the case of deepwater wells, for which inadequate knowledge of the temperature can have severe consequences.
During drilling operations, fluid cooldown in the riser can affect mud rheology, especially for synthetic-based muds (SBMs), and can cause high circulating pressure when pumping is resumed after shutdown or cause excessive surge and swab pressures when the pipe is run in or pulled out of the hole. Low fluid temperature combined with relatively high pressures, such as those that may occur in deepwater drilling conditions, could also cause formation of gas hydrates, resulting in several adverse effects, such as plugging at the blowout preventers (BOPs) or in the riser.
In the temperature range encountered when cementing shallow strings of deepwater wells, a deviation of 5 to 10°C (9 to 18°F) in the circulating temperature can greatly impact the design of the cement slurry because the setting time and the compressive strength development can be quite sensitive to temperature in the 5 to 15°C (41 to 59°F) range. Predicting the temperature profile at the end of cement placement is the first step toward giving reliable estimates of compressive strength development for the conductor and surface casings. This can lead to substantial savings through a better estimation of the time necessary to wait on cement before releasing the casings.1
The industry relies on three main methods for predicting temperature profiles in a well while circulating mud, placing cement, and waiting on cement.
It is acknowledged that API correlations should be used with caution (to say the least) for deepwater wells because the data set used to derive these did not include any from deepwater wells. Local correlations will not be addressed in this paper because of their limited applicability. Basically, the industry relies on numerical simulators. As is always the case for complex processes like circulating fluids in a wellbore, these simulators need to be validated and calibrated with field data. Indeed, numerical simulators were validated against the API temperature database or other, more complete data sets gathered on a given well. To the best of the authors' knowledge, this exercise has not been done with deepwater wells because of the lack of field measurements.
Joint Industry Project
A JIP among four major oil companies and a service company was initiated to gather circulating-temperature data in deepwater wells. The wells' locations were chosen to be representative of the major deepwater fields around the world (i.e., Gulf of Mexico, Brazil, Indonesia, and west Africa).
The primary objective of the project was to better understand a specific aspect of deepwater wells - the cooling effect of the sea in two different situations (i.e., with and without a riser). This objective had to be reached by interfering as little as possible with standard drilling operations. With this in mind, the project members agreed on a tool to be used to perform the temperature measurements as well as on procedures to gather all necessary data and interpret the measurements.
Most downhole temperature measurements were accomplished with a tool developed by Mobil in the early 1990s6 that is mounted inside the drillpipe (see Fig. 1). It is completely reusable in the field and very similar to the standard directional- survey tools used on many rigs. It had been used extensively in oil wells in depths up to 6,000 m (20,000 ft) and pressures up to 76 MPa (11,000 psi) to obtain low-cost temperature data during drilling, logging, and running casing operations throughout Texas, eastern Oklahoma, western Colorado, and in the Arun field in Indonesia. In general, using the tool was found not to interfere with normal operations.
The system is composed of a rugged, battery-operated, programmable temperature sensor with a memory contained in a standard body housing. The sensor is calibrated up to 149°C (300°F), and readings as high as 162°C (324°F) have been made in the field. The sensor can be programmed to store readings at a selected time interval and can take up to 1,000 readings per run. Once the data is recorded, the sensor is taken out of its housing, and the data can be downloaded by means of a simple personal computer interface. The nominal sensor operating life before recalibration and battery change amounts to a total run time of 800 hours.
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