Downhole Measurements of Synthetic-Based Drilling Fluid in an Offshore Well Quantify Dynamic Pressure and Temperature Distributions
- W.W. White (Marathon Oil Co.) | Mario Zamora (M-I Drilling Fluids LLC) | C.F. Svoboda (M-I Drilling Fluids LLC)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 1997
- Document Type
- Journal Paper
- 149 - 157
- 1997. Society of Petroleum Engineers
- 1.6 Drilling Operations, 4.3.4 Scale, 1.10 Drilling Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.6.1 Drilling Operation Management, 1.14 Casing and Cementing, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.1 Well Planning, 1.6.1 Drilling Operation Management, 1.7.5 Well Control, 3 Production and Well Operations, 1.11 Drilling Fluids and Materials
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Accurate downhole and surface measurements of a synthetic-based drilling fluid were taken in a Gulf of Mexico well to resolve variances between actual and calculated pump pressures and to quantify equivalent circulating densities. Current American Petroleum Inst. (API) equations seriously underestimated drillstring losses, which accounted for the pump-pressure differences. Conversely, annular losses were much lower than predicted.
The drilling industry cannot consistently match calculated and actual pump pressures and is uncertain of the reliability of equivalent-circulating-density (ECD) predictions when using oil-based muds. Sensitivities to temperature and pressure are the most often cited reasons for the discrepancies. Attempts to compensate for these effects with oil-based muds have not met with widespread success.
Similar difficulties are encountered with synthetic-based muds (SBM); however, concerns are more acute. Pump-pressure calculations with SBM's can be off as much as 35%. The high unit cost per barrel of SBM's makes lost circulation a serious risk if ECD values are unreliable. Related problems (also affected by hydraulics) include surge/swab pressures while tripping, sizing of mud pumps, hydraulic optimization, well control, and general well planning.
Lack of quality field data is perhaps the root cause of difficulties associated with predicting SBM hydraulics. Full-scale field tests, while very costly, are invaluable since high-temperature, high-pressure (HTHP) field conditions cannot easily be duplicated in laboratories or shallow test wells.
A special team headed by Marathon Oil Co. successfully instru-mented and collected a very large volume of hydraulics data on a well in the Gulf of Mexico at 12,710-ft measured depth. The rest of the team was composed of representatives from the drilling contractor and key service companies. This well was chosen, among other reasons, because pump-pressure calculations using current API equations1 were 1,300 psi less than actual. Also, calculated ECD's were considered abnormally high, though lost circulation with the synthetic-based drilling fluid was never imminent.
The primary goal of this project was to collect sufficient data to resolve discrepancies concerning pump pressures and ECD's. Secondary targets included measuring and evaluating surge/swab pressures, bit pressure loss, equivalent static density (ESD), and mud-temperature profile. Planning efforts streamlined the testing program and helped complete the project within the rig-time allocation. The few problems encountered did not jeopardize project goals.
The focus of this paper is on the downhole and surface measurements taken on this offshore well over a 36-hour period. The information, presented in a format suitable for both cursory and detailed analysis, provides insight into the downhole behavior of synthetic-based drilling fluids. The data set is being used to develop suitable models; however, a detailed discussion of modeling is beyond the scope of this paper.
Instrumentation and Test Program
The well selected for the test was in 420 ft of water in Block 89, South Pass, Gulf of Mexico. Testing was conducted after running and cementing a single-weight intermediate string of 11 7/8-in. casing to 12,710-ft MD. Fig. 1 shows the well profile at the time of the test with the 5-in. drillstring run to 12,439-ft MD (12,186-ft true vertical depth [TVD]). Drillstring details also are given in Fig. 1. The mud was the same 11.5-lbm/gal polyalphaolefin (PAO)-based synthetic drilling fluid used to drill the long intermediate-casing interval.
Rig cost clearly was the most pressing issue. Multiple downhole sensor packages were installed to minimize rig time. This scheme also significantly improved data quality, because measurements were taken simultaneously at different depths. The alternative (common for this type of project) was to use a single sensor package that could be repositioned by moving the drillstring.
Sensor packages were installed on the drillstring. The top sensors were placed at about 3,400-ft MD, just below the depth where the maximum angle of 24° was reached. The middle package was positioned at 8,400-ft MD, where the mud was expected to reach maximum circulating temperature. The bottom sensors were installed around 12,400-ft MD, just above the 10 5/8-in. rock bit and bit sub with float. The wellbore angle at the bottom of the interval was 11°. Fig. 1 provides additional details on sensor packages.
Redundancy insured data were obtained at all sensor locations. Two gauge carriers were run at each position. Each carrier package included an internal (drillstring) and an external (annulus) high-resolution, digital recorder to measure pressure, temperature, and time. For additional backup, three mechanical gauges were installed in the bottom sensor package. Total gauge count was 15.
Halliburton memory recorders (HMR)2 were selected for the downhole sensors. These recorders can store 32,000 data sets and can be programmed to collect data at fixed or variable rates. The stored data are later downloaded to a microcomputer for analysis. The highly accurate recorders reportedly measure pressures to 16,000 psia ±1.0 psia at temperatures to 356°F.
An external and internal HMR at each sensor location were programmed to record data at 2-second intervals to achieve high resolution. Remaining recorders were programmed for 4-second intervals to insure data were collected over the entire testing period. All HMR's were set to a 30-second recording interval for the first 7 hours to save memory while tripping in the hole. Sensor batteries were installed simultaneously in all recorders to synchronize time for correlation purposes. Data analysis would have been very difficult otherwise.
To avoid damage to the gauges, it was decided to not rotate the drillstring and to limit shock loads during surge/swab testing. However, the HMR's proved both accurate and reliable. Only one HMR failed to provide usable data. In fact, the initial gauge carrier with one mechanical and two memory gauges was accidentally dropped down the mouse hole during makeup. The gauges were repositioned up the string at lower-priority spots; all three gauges performed properly.
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