Performance of Horizontal Wells in the Helder Field
- Patrick J. Murphy (Unocal Netherlands B.V.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1990
- Document Type
- Journal Paper
- 792 - 800
- 1990. Society of Petroleum Engineers
- 5.7.2 Recovery Factors, 4.1.5 Processing Equipment, 5.5 Reservoir Simulation, 1.6 Drilling Operations, 5.2 Reservoir Fluid Dynamics, 3 Production and Well Operations, 3.3.1 Production Logging, 4.1.9 Tanks and storage systems, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control, 4.2.3 Materials and Corrosion, 5.5.8 History Matching, 1.6.6 Directional Drilling, 2.4.5 Gravel pack design & evaluation, 5.1.2 Faults and Fracture Characterisation, 2 Well Completion, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.3.4 Scale, 3.1.2 Electric Submersible Pumps
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The Helder oil field on the Dutch Continental Shelf was virtuallyredeveloped with the drilling of eight horizontal wells from Dec. 1986 to Jan.1988. The first horizontal well came on production Jan. 5, 1987. The success ofthese wells, all sidetracked from existing wells and the first horizontal wellsin the North Sea, led to a complete reappraisal of Unocal Netherland B.V.'sreservoir development philosophy. This paper reviews the background,performance, and benefits of the Helder field performance, and benefits of theHelder field horizontal wells through April 1988.
The major benefits of horizontal wells (i.e., increased productivity andimproved sweep efficiency) have been recognized for some time from a reservoirmanagement point of view. The main obstacles to realizing these benefits havebeen the technical difficulty and high cost of drilling horizontal wells. WhenUnocal Netherlands B.V. began investigating the possibility of drillinghorizontal wells (mid-1986), the literature indicated that the cost of thesewells would be four to six times that of equivalent conventional wells.
The economic success of the Helder field horizontal wells is attributablemainly to improved drilling technology and planning. Ref. 1 describes thedrilling aspects of these wells.
This paper discusses the reservoir engineering aspects of the horizontalwells drilled in the Helder field, including (1) justification for and choiceof the first well, (2) field redevelopment, (3) performance and benefits, and(4) optimum production rate. It also briefly describes the drilling andcompletion method.
The Helder field is located in Block Q/1 of the Dutch North Sea, about 62miles [100 km] northwest of Amsterdam, and lies in 85 ft [26 m] of water (Fig.1). Block Q/1 was acquired by Unocal Netherlands B.V. and its partner NedlloydEnergy B.V. in 1967. The field was discovered in April 1979 and productionbegan in Oct. 1982. Two other production began in Oct. 1982. Two other oilfields, Helm and Hoorn, were brought on production during this time. Helm fieldproduction began in Oct. 1982, and Hoorn production began in Oct. 1982, andHoorn began in July 1983. These three fields (Fig. 2) represent the firstcommercial oil production from the Dutch sector of the North Sea. productionfrom the Dutch sector of the North Sea. Between 1982 and 1984 the Helder fieldwas developed with 12 conventional wells from a centrally located wellheadplatform. In 1986, a previously drilled appraisal well (Well Q/1-10) was tiedback to Helder field's Platform A with a satellite tripod tower, Platform B.All the original wells were completed with gravel packs for sand control.
Although some wells were initially produced under natural flow, electricproduced under natural flow, electric submersible pumps (ESP's) were eventuallyinstalled in all wells to compensate for declining reservoir pressure andincreasing water cut. The maximum size of the first pumps was limited to 83.5hp [62.3 kW] pumps was limited to 83.5 hp [62.3 kW] because of platformpower-supply limitations. In 1985 and 1986, increasing water cuts andcontinuously declining reservoir pressure led to the installation of additionalpower generation equipment to enable larger pumps (250 hp [187 kW]) to berun.
Before production started on the first horizontal well (Jan. 1987), Helderfield produced 6,530 BOPD [1038 m3/d oil] for produced 6,530 BOPD [1038 m3/doil] for a gross fluid offtake of 108,000 BFPD [17 170 m3/d fluid]. Individualwells produced at rates up to 12,000 BFPD [1908 produced at rates up to 12,000BFPD [1908 m3/d fluid], with water cuts between 84 and 97%.
Helder Field Description
Helder field (Figs. 3 and 4) is a small accumulation of 22 degrees API[0.92-g/cm3] -specific-gravity crude in a relatively simple, slightly faulted,anticlinal structure at a depth of 4,600 ft [1402 m]. Original oil in place isestimated to be 70 MMSTB [11.2 X 106 stock-tank m3]. Production is from theLower Cretaceous Vlieland sandstone, which has excellent reservoircharacteristics and permeabilities that range from 1.0 to 6.0 darcies. Thesandstone is friable and of intermediate wettability and contains a partiallybiodegraded oil with a 30-cp [0.03-Pa.s] viscosity. The field is underlain bywater over its entire 1,140 acres [461 ha] of closure and has a maximum oilcolumn of 131 ft [40 m].
Pre-1987 Field Pre-1987 Field Development Philosophy
Early water breakthrough and rapidly increasing water cut were expected inthe original wells because of the high viscosity ratio, the flat fieldstructure, and the high vertical permeability of the sand. The majority ofwells produced water within a few days of production startup (Table 1).
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