Development of a Marginal Property: Petronella Field
Authors: Horne Jerrold S. , Berkoz Afsin , Wood Leslie R. 
Published: December 2007

Texaco has chosen subsea techniques to develop a small reservoir located 6.5 miles [10.5 km] from the Tartan platform in the U.K. sector of the North Sea. Water depth in the area is approximately 430 ft [131 m].

This paper is a case study that discusses evaluation criteria used in determining the development scenario. Reservoir and geologic data relative to the accumulation are reviewed. Also discussed are the development and results of the well drilling program, with emphasis on the procedure used to develop the well testing program. Reservoir simulation performed in support of project evaluation is presented and results are performed in support of project evaluation is presented and results are reviewed. We also discuss the design procedure, including selection criteria for surface and subsurface equipment, and review the economic evaluation.

Introduction

The Petronella field is located 6.5 miles [10.5 km] southeast of the Tartan ‘A’ production platform and 5 miles [8 km] south of Highlander field in Block 14/20b in the U.K. sector of the North Sea (see Fig. 1). Average water depth in the area is 430 ft [131 m].

Well 14/20–1, the discovery well on the block, was drilled in Feb. 1975 to a depth of 9,034 ft [2753 m] subsea. The well encountered a hydrocarbon section of Upper Jurassic Age with a gross thickness of 768 ft [234 m] (275 ft [84 m] net) at 7,269 ft [2215 m] subsea. An oil/water contact (OWC) was encountered at 7,650 ft [2331 m] subsea.

A drillstem test (DST) was conducted on a 20-ft [7-m] interval from 7,354 to 7,374 ft [2241 to 2247 m] subsea. The test consisted of five flow periods: an initial cleanup flow, the main flow (4,537 B/D [721 m3/d] oil), and three higher-rate flows (5,898, 6,722, and 7,605 B/D [937, 1068, and 1209 m3/d] oil). Analysis of the data showed a variation in PI from 10 to 15 B/D-psi [0.13 to 0.34 m3/d kPa] oil (including effects from formation damage). Estimates of PI with zero skin indicated that values of 100 to 200 B/D-psi [2.3 to 4.6 m3/d kpa] oil could be expected.

API gravity of the crude oil produced during the test was 40.2 degrees [0.82 g/cm3] with a GOR of 1,036 scf/STB [186 std m3/stock-tank m3]. Reservoir pressure and temperature measured during the DST were 3,340 psi and 160 degrees F [23 MPa and 71 degrees C], respectively. After completion of the test, the well was plugged and abandoned.

Four additional exploratory/appraisal wells were drilled in the vicinity of Well 14/20–1 between 1975 and 1980 to delineate the accumulation (Wells 14/20–2, 3A, 10, and 11). As defined, the structure is a tilted fault block trending approximately east/west across the southern portion of Block 14/20 (see Fig. 2). It is bounded by faults that are part of the principal bounding structures on the southern margin of the Witch Ground Graben.

Development Drilling

Well 14/20–16. In 1985, Well 14/20–16, a development well, was drilled. The purpose of the well was to provide a productive outlet for the accumulation that had been defined by the five exploration/appraisal wells. The well was drilled to a total depth of 8,110 ft [2472 m] (8,028 ft [2447 m] subsea) and encountered 184 ft [56 m] of hydrocarbon-bearing sand of which 138 ft [42 m] is oil bearing. A simplified lithological section of the reservoir in Well 14/20–16 is presented in Fig. 3.

The base of the pay zone is about 190 ft [58 m] above the OWC encountered in Well 14/20–1. The well also determined a gas/oil contact (GOC) at 7,316 ft [2229 m] subsea.