Results of a Steamdrive Pilot Project in the Ruehlertwist Field, Federal Republic of Germany
Authors: Proyer G. , Chaziteodorou G. , Muss H. , Rosskamp M. 
Published: December 2007

Production from the area of the Ruehlertwist field close to the northern aquifer is governed by pressure maintenance by water influx, sustained by reinjection of produced water downdip of the oil/water contact (OWC) in the north of the structure. Because of the high in-situ viscosity (175 mPa·s [0.175 cp]) of the 0.9-g/cm3 [25°API] crude in this area, only 22% of the stock-tank oil initially in place (STOIIP) has been recovered. Therefore, it was decided by the consortium operating the field (BEB, Deilmann A.G., Preussag A.G., and Wintershall A.G. as operator) to perform a pilot test to investigate the feasibility of steam injection under waterdrive conditions in this highly watered-out part of the field. In Dec. 1978 steam injection into Well Rt 208 was started. The second well, Rt 56, began steam injection in April 1979. The 580 000-m2 [143-acre] pilot area contained 2.655×106 m3]17×106 bbl] STOIIP. By the end of Feb. 1983 about 1 080 000 m3 [138,139,840 cu ft] steam (32.8% PV) have been injected into the reservoir. During these 4 years the additional recovery attributable to steamflooding accumulated to up to 6.8% STOIIP. This paper describes the reservoir, the necessary facilities, and the pilot project performance. Conclusions drawn from the pilot performance will be considered for future production strategy.

Introduction

The Ruehle structure, which comprises the Ruehlertwist and Ruehlermoor oil fields, is located in the Emsland area of the Federal Republic of Germany near the Dutch border (Fig. 1). It is an east-west-trending anticline of the Lower Cretaceous Age. The oil-bearing area of the structure is roughly 27 km2 [10 sq miles] of which one quarter belongs to the Ruehlertwist oil field. This field was discovered in 1943 and has been developed since 1948–49. A total of 138 wells with a spacing of approximately 200 m [656 ft] were drilled by the end of 1957.

The main oil reservoir consists of the Bentheim sandstone (Valanginian), an unconsolidated sandstone at an average depth of 800 m [2,625 ft]. The Bentheim sandstone consists of four layers:Flaser Sandstone (approximately 8 to 10 m [26 to 33 ft] gross thickness),Upper Sandstone (approximately 8 to 22 m [26 to 72 ft] gross thickness),Clay (approximately 2 to 4 m [7 to 13 ft] gross thickness), andLower Sandstone (approximately 6 to 8 m [20 to 26 ft] gross thickness).

The main producing zone in the Ruehlertwist oil field is the Upper Sandstone. It is a well-sorted sand of medium-size quartz grains and a low clay content in the upper part of the zone. The lower part of the Upper Sandstone is also well sorted, containing a very fine-grain sand with low clay content. The clay content of the zone gradually decreases from base to top and, hence, permeability increases. The range of permeability for air is on the order of 300 to 10,000 md. Typical core and log data of Wells Rt 25A and Rt 187 are shown in Figs. 2 and 3.

Three drive mechanisms are used in the Ruehlertwist oil field (Fig. 4).In the northern and southwestern areas, primary production is obtained by edgewater drive.In the top structure area, solution gas drive and fluid expansion are the primary production mechanisms.The southeast area has increasing clay content and decreasing permeability to the southeast and an east-west-trending fault. This part of the field is sealed from the edgewater drive and driving energy comes from solution gas and expansion only.

The depth of the Upper Sand is 700 m [2,297 ft] at the crest of the anticline, 870 m [2,854 ft] on the north flank at the oil/water contact, and 800 m [2,625 ft] on the south flank. The dip of the producing formation ranges from 0 to 9°, being less in the northern part of the field.

Until the 1960's, the top area and the southeast part of the Ruehlertwist field were produced by fluid expansion and solution gas drive. To improve the low primary recovery factor, which resulted from the high in-situ oil viscosity of the 0.9-g/cm3 [25°API] crude, water injection was started in the southeastern part in 1961 and in the top area of the field in 1968. The recovery resulting from primary and secondary energy (repressuring of the depleted reservoir by natural water influx and cold water flooding) was low because of the unfavorable mobility ratio and the type of reservoir (complex petrophysical characteristics including structural barriers created from major east-west faulting, which separates the reservoir into sections more or less affected by the edgewater drive).