Turbodrilling Performance Offshore Qatar (includes associated paper 14482 )
- L.A. Rana (Qatar General Petroleum Corp.) | E.A. Abdul Rahman (Qatar General Petroleum Corp.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1984
- Document Type
- Journal Paper
- 1,727 - 1,733
- 1984. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 1.10 Drilling Equipment, 1.11 Drilling Fluids and Materials, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.6 Compressors, Engines and Turbines, 1.6.1 Drilling Operation Management, 1.14 Casing and Cementing, 1.6.10 Running and Setting Casing, 1.5 Drill Bits, 1.6.6 Directional Drilling, 1.5.1 Bit Design, 1.6 Drilling Operations
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Until the first quarter of 1979 we routinely rotary drilled our offshore vertical development wells with tricone bits. Turbodrilling was introduced in the second quarter of 1979 for 17 1/2- and 8 1/2-in. [44.5- and 22-cm]hole sections and in the first quarter of 1980 for the 12 1/2-in. [31-cm]hole section. This resulted in avoiding and/or minimizing downhole problems and eliminating 7- and 4 1/2-in. [18- and 11 -cm] liners. As a result of introducing these practices a 50% time saving and a 30% cost saving has been achieved, equivalent to $550,000/well.
This paper reviews the drilling performance for nondeviated development wells from the beginning of 1978 to mid-1981 for three producing oil fields:(1) Idd el Shargi field, where 35 wells have been drilled with an average depth of 7,900 ft [2408 m] and oil production of 20,000 B/D [3180 m3/d],(2) Maydan Mahzam field, where 35 wells have been drilled, with an average depth of 9,000 ft [2743 m] and oil production of 80,000 B/D [12 719 m3/d], and (3) Bul Hanine field, where 30 wells have been drilled, with an average depth of 9,300 ft [2835 m] and oil production of 195,000 B/D [31 003 m3/d].
Three jackup rigs are operating. Ten exploration, appraisal, or development wells are being drilled and five wells are worked over per year. Fig. 1 shows the areas of operation.
Overall, 23 wells have been drilled and completed during this period. Since mid-1981 most of the wells have been drilled as deviated wells, but in deeper horizons some wells also are drilled for exploration. As a result of this, standard practices for directional drilling still are being established. Until the first quarter of 1979 the wells routinely were drilled by using rotary drilling techniques. The main problems encountered were (1) drillstring twistoffs in the 17 1/2-in. [44.5-cm] hole section, (2) lost circulation and hole washouts in the 17 1/2-in. [44.5-cm] hole section, (3) swelling and caving shale, and stuck pipe in the 12 1/2 -in. [31 -cm] hole section,(4) differential pressure sticking in the Arab formation, and (5) poor penetration rates.
To avoid or minimize these problems 7-in. [18-cm] liners were run in the Arab reservoir and 7- and 4 1/2-in. [18- and 11-cm] liners were run in the Uwainat reservoir. Along with the introduction of turbodrilling, the polymer drilling mud was improved and mud cleaners were installed on all rigs.
As a result of better mud control and new drilling procedures, downhole problems have been largely minimized. Because of this, it was no longer necessary to set liners in the Arab and Uwainat reservoirs.
Turbodrilling. The application of the turbodrilling technique was pursued for the following general reasons.
1. More power can be delivered to the bit by a downhole motor for a given power applied at surface.
2. It is cost effective when drilling with high unit costs, as generally are experienced when drilling with offshore mobile units.
3. Running a turbine forces all drilling personnel to adhere to very standardized drilling practices.
4. More effective bit optimization results because of standardized practices.
5. High stress levels in the drillstring resulting from rotation can be reduced effectively by using a downhole motor.
6. Higher speed of rotation suits diamond bits. Optimization of turbodrilling and bit design is carried out under very stringent economic rules as indicated in the following section.
Optimization Method. To take full advantage of new drilling bit technology but avoid the risk of costly trials by bit suppliers at our expense, the following policy has been developed for the case that bit suppliers submit a proposal for the use of a new bit type.
On the basis of the actual performance of the presently used type(s), a norm for a certain rate of penetration and cost per foot (CPF) is set. If the actual CPF is higher, the extra expenditure is deducted from the bit cost. The full bit cost is paid only if the drilling CPF is equal or lower than the norm used in the break-even calculation.
This method has worked out favorably. Bits have been optimized, and further improvements still are being achieved while minimizing exposure to decrease in performance. Table 1 presents some technical information on turbodrills and a mud motor.
The 26-in. [66cm] Hole Section. This section is rotary drilled to about 650 ft [198 m] with rotary bits of the 1-1-1 type by using seawater and dumping returns at seabed.
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