To date, several wells have been drilled in the Friesland/Groningen area of northern Holland. Historically, catastrophic cutter damage/failure in the 12 1/4" Triassic section resulted in inconsistent and unacceptable bit performance. Here, the Triassic is an interbedded formation containing hard dolomite and anhydrite stringers and abrasive sands. The transition from a softer to harder formation at high inclination evidently initiated bit and drillstring vibrations, thus causing premature cutter failure of the PDC bits used in the program. This paper presents a detailed analysis of the 12 1/4" section conducted after the drilling of Well No. 1. The recommendations arising from the study concentrated on the use of a real-time downhole vibration monitoring or VSSMWD tool (Vibration Stick Slip) in combination with revised drilling practices to reduce vibrations when encountering the interbedded formation. Thus, on Well No, 2, nearly all of the 2358-m Rijnland and the hard and abrasive Triassic forrntions were drilled with one PDC bit on a rotary assembly, where previously six bits were required. The authors will illustrate the benefits of a detailed interval analysis and discuss the role of the VSS system and the dring crew in addressing catastrophic drillstring and bit vibrations. P. 925

This paper was prepared for presentation at the 1999 SPE/IADC Drilling Conference held in Amsterdam, Holland, 9-11 March 1999.

The Brent field is located in the Viking Graben of the northern North Sea and produces from the Brent Formation and the deeper Statfjord Formation. Virgin reservoir datum pressure in 1976 was approximately 5,655 psi at 8,700 ft TVDSS. Pressure support was maintained until the 1998 since when reservoir pressure has been depleting at about 500 psi per year. The current datum pressure in the Brent units is approximately 1600–1700 psi. Significant lost circulation problems started to be experienced in the late 90's and a study identified the cause as the narrowing of the mud weight window as reservoir depletion gradually lowered the fracture gradient [ref 1]. Mud weights have been lowered to mitigate against the costly lost circulation events. The mud weights currently used are typically 700–900 psi less than the shale pore pressure (i.e. underbalance). Two case histories from sub-horizontal wells last year illustrated that the shales can be drilled over 900 psi underbalanced with no indication of shale failure, however, when running in liners they both hung-up where shales had collapsed. Based on this experience, the minimum mud weight for drilling the sub-horizontal reservoir sections has been set at 700 psi underbalance relative to the interbedded shale pore pressure. Reservoir depletion has reached the point where the (static) minimum mud weight for shale stability is almost equal to the fracture propagation pressure (FPP) for the reservoir sands. In the first half of 2002, 5 of the 7 wells drilled experienced lost circulation. The average losses volume per well was over 5,000 bbls with nearly 19,000 bbls being lost on one well. Of more significance is the NPT associated with the losses, this averaged over 300 hours per well. The average monetary cost of the lost time and mud volume was close to £1 MM per well. In an environment drilling low cost sidetracks, accessing reserves of 1–2 MM boe, this situation was unsustainable. A task force set about finding possible solutions to combat the lost circulation problems. After technical review, including laboratory testing, a recommendation was made for a size and concentration of graphite to be added to the OBM. In 10 field trials to date all the sections reached TD without inducing lost circulation, however, 4 of the 10 sections did experience losses when running the liner and/or circulating prior to cementing. With the addition of the graphite the average losses per well has dropped from 5,238 bbls to 621 bbls and the associated NPT has dropped from 302 hours to less than 1 hour per well. Recent field data suggest that the graphite could add approximately 1000 psi to the fracture breakdown pressure. This opens a host of possibilities for future infill drilling in depleting reservoirs. Introduction The Brent field is located 186 km northeast of the Shetland Islands in the UK North Sea and has a STOOIP of 3.8 billion stb and a GIIP of 7.5 Tscf (figure 1). The field was discovered in 1971 and was brought on production in 1976, with annual production peaking in 1984 at 410 Mbbl/d. Since the 1980s, oil production has been experiencing decline, but because of the high solution GOR (ranging from 250–980 v/v) substantial gas reserves remain, dissolved in the residual and by-passed oil. In 1992 the decision was taken to depressurise the Brent Field to recover an additional 1.5 Tscf of gas and 34 MMstb of oil, so extending the end of field life by 5–10 years. This required a £1.3 billion redevelopment of three of the four Brent platforms to install pressure facilities for low pressure operations, to reduce operating costs, to implement safety upgrades and to refurbish the facilities.

No abstract