Abstract

An engineering evaluation was conducted to determine development feasibility of a heavy oil prospect located in the UK sector of the North Sea prospect located in the UK sector of the North Sea in 348 ft of water. The reservoir is located at approximately 3,000 ft. The matrix is highly unconsolidated and contains crude oil with a viscosity of 132 cps at reservoir conditions. In addition, the oil column is underlain and in direct contact with a large water zone. The paper presents a procedure to evaluate a potential offshore field. The procedure uses potential offshore field. The procedure uses reservoir, drilling, and operations engineering technology in developing a screening technique to determine how to proceed with evaluating the development. Simulation was used to evaluate reservoir performance under depletion drive, natural influx, performance under depletion drive, natural influx, and water flood, Thermal and non-thermal enhanced oil recovery (EOR) methods were evaluated using analytical techniques. Results of the simulation and analytical techniques are presented. Results of sensitivity studies to determine the effect of aquifer strength, vertical communication, and production rate on ultimate recovery of the high production rate on ultimate recovery of the high viscosity oil are also presented. The impact of horizontal wellbores on ultimate recovery was determined by simulation. The effect of vertical location of the wellbore within the reservoir and wellbore length were modelled and results are presented. presented. Work required on the directional drilling and well test programs for the exploratory wells to evaluate the shallow, unconsolidated reservoir are discussed. The technique of drilling the proposed multiple drainhole wells is reviewed. Production Systems Optimisation (PSO) was used to evaluate factors not normally considered in reservoir simulation. PSO is an analytical tool to calculate pressure losses as a function of rate from pressure losses as a function of rate from the reservoir to the stock tank. The objective of the analysis is to economically design the most efficient production system over the life of the well. Formulas used in the technique which are applicable to other fields are presented in the paper. The effect of pipe diameter, gravel pack paper. The effect of pipe diameter, gravel pack permeability, and screen diameter on production permeability, and screen diameter on production rates are discussed. The effect of water production is also included.

Introduction

The area of evaluation is located in the United Kingdom (UK) sector of the North Sea approximately 40 miles [64 km] north-east of Peterhead, Scotland and 55 miles [88.5 km] south-east of the Orkney Islands (see Figure 1). Texaco was awarded the Block on 15 March 1972 in the 4th Round Awards under Licence P. 237. Well No 1, the discovery well, was spudded 29 April 1977 and drilled to a total depth of 4778 feet [1456.3 m] on 18 May 1977. Details of the casing, cementing, and mud programmes are presented in Table 1. The well encountered a poorly cemented, friable oil bearing formation of Lower Cretaceous - Barremian age at 2877 feet [876.9 m] (-2791 feet subsea [-850.6 m subsea]). A structure map is presented in Figure 2. A portion of the open hole presented in Figure 2. A portion of the open hole log across the reservoir section is presented in Figure 3. The hydrocarbon bearing zone has a thickness of 203 feet gross and 191 feet net [61.87 m gross, 58.2 m net]. Average porosity and water saturation in the oil column are 31% and 17%, respectively. The oil-water contact is at 3080 feet [938.7 m] based on log analysis and oil shows. The oil column is underlain and in direct contact with a water zone approximately 100 feet [30.48 m] thick. A drill stem test (DST) was conducted over the interval 2879 to 2940 feet [877.82 to 896 m]. Approximately 10 barrels [1.59 m3] of 17.6 API gravity [.95g/cm3] oil with a viscosity of 132 cps [132 Pa.s] at reservoir conditions and a gas-oil ratio (GOR) of 42 SCF/STB [7.48 m3/m3] were produced during the test. Data obtained during the DST indicated an average reservoir pressure of 1332 PSIA [9.18 MPa] at a datum of 2800 feet [853.4 m] and a permeability of approximately 3000 mD [2.96u m]. The well was plugged and abandoned after completing the DST. plugged and abandoned after completing the DST. Target oil-in-place in the unconsolidated Lower Cretaceous reservoir underlying Block 13/22 is approximately 2 billion barrels [317.8 × 10(6) m3] based on data obtained by drilling Well No. 1 and geological/geophysical data. Previous in-house studies downgraded the Block's development potential due to the high in situ viscosity and comparatively shallow reservoir depth. However, enhanced oil recovery (EOR) techniques and improved methods for drilling and completing wells to optimise recovery from viscous oil reservoirs are now available which improve development feasibility of the Block.

RESERVOIR ENGINEERING

Computer simulation was used to evaluate reservoir performance under conventional recovery methods performance under conventional recovery methods (depletion drive, aquifer influx, water injection). In addition, thermal and non-thermal EOR methods were evaluated. Thermal EOR methods (in situ combustion, steam drive) were analytically evaluated. Nonthermal EOR methods (polymer flooding, miscible and immiscible CO injection) were also evaluated. Details of the evaluation of each recovery method including assumptions, data sources, and results are presented below.

CONVENTIONAL RECOVERY METHOD

The purposes of evaluating conventional recovery methods were to identify the parameters controlling recovery of the viscous crude, determine the ultimate recovery under conventional North Sea operation methods, and provide a benchmark for evaluating the predicted results from EOR techniques. Three conventional drive mechanisms (depletion, aquifer influx, and water injection) were evaluated. Sensitivity studies on the effect of completion interval, vertical permeability, and production rate on ultimate recovery were made for all three drive mechanisms. The impact of water influx for the aquifer drive case was evaluated. The impact of completion technique (normal versus horizontal) on recovery of the viscous crude oil by conventional methods was determined. The conventional recovery methods were evaluated using a commercially available reservoir simulator. The model was defined areally using a 14 by 14 cell grid. Dimensions of 94.27 feet by 94.27 feet [28.73m by 28.73 m] were used for each cell. Total surface area of the model is 40 acres [16.18 × 10(4) m]. Original oil-in-place in the 40 acre [16.18 × 10(4) m] model is 15.49 MMSTB [2.47 × 10(6) m3]. Seven layers define the model vertically. The top five layers, each 40 feet [12.19 m] thick, describe the gross oil zone. A net to gross ratio of 0.955 was used to adjust each layer to a net thickness per layer of 38.2 feet [11.64 m].

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