The Use of Routine and Special Core Analysis in Characterizing Brent Group Reservoirs, U.K. North Sea

Abstract

Summary This paper describes the use of core analysis data, both routine and special, in characterizing the Brent Group reservoirs in the U.K. North Sea. The results of various special ore analysis tests conducted over the years indicate that coring fluid, core preservation, and laboratory procedures are important in defining relative permeability and capillary pressure. Examples are given of (1) the effect of oil-based mud filtrate on rock wettability; (2) the effect of extraction, drying, and test procedures on laboratory waterflood performance; and (3) variation of relative permeability arnong facies. Results also suggest how petrography may be used in assigning relative permeabilities by facies. Analysis of routine core data shows complexity within the Brent Group reservoirs even within relatively "uniform" sands. This is reflected by large differences in relationships between porosity and permeability. Examples are presented of such differences from well to well within the same area of a field, within the same formation in a single well, and between the oil and water zones. Examples are given of the potential to correlate these differences with log responses. Such a correlation could predict permeability variation in uncored wells more accurately. A technique to identify different porosity/permeability relationships within a well is presented. Introduction Esso E&P U.K. has an interest in several North Sea oil fields that produce from the Brent Group sands of Middle Jurassic age. These fields include Brent, Cormorant, Dunlin, Eider, Tern, and Osprey. These fields, which are opened by Shell U.K. E&P, are located in approximately 500 ft of water in the North Viking graben, 100 miles northeast of the Shetland Islands (Fig. 1). The Brent Group contains five formations representing a transgressive/regressive depositional sequence. The major regressive phase comprises a fluviodeltaic system. The section is illustrated by the type log in Fig. 2, which also illustrates the stratified nature of the sands and the permeability contrast. The depositional sequence, starting from the base and progressing upward, includes a transgressive lag depos it (Broom), prodelta shales and lower to upper shoreface sands (Rannoch), a beach and barrier bar complex (Etive), fluvial and lagoonal sediments (Lower, Middle, and Upper Ness), and a transgressive marine sand (Tarbert). The Tarbert and Ness sandstones generally are quartzose while the Etive, Rannoch, and Broom are quartzofeldspathic. Diagenesis is evidenced by the presence of kaolinite and illite along with pore-throat reduction resulting from compaction and quartz overgrowth. The conversion of feldspar to kaolinite is more widespread in the lower formations with further conversion to illite occurring in deeper areas. A more detailed description of the geology of the Brent Group is contained in Ref. 1. The need for accurate reservoir characterization is important, not only because of the geologic complexity but also because of the field development methods, which often involve concurrent waterflooding of the entire section with a limited number of fully perforated producers and injectors. In this situation, reservoir behavior is a function of many different reservoir characteristics. For example, the early appearance of water in producing wells may be caused by inefficient displacement resulting from unfavorable relative permeability relationships, severe water underrunning resulting from an adverse permeability profile within a major sand, or rapid water advance through a sand with very high permeability. A good understanding of the reasons for specific reservoir behavior is important in identifying proper remedial action. Good core coverage and full use of the resulting core data are required to manage the complex reservoirs of the Brent Group. Special Core Analysis Esso has conducted considerable special core analyses for Brent Group reservoirs, primarily in the measurement of relative permeabilities, kr; capillary pressures, Pc; and remaining oil saturations (ROS's). Special attention has been given to preservation of wettability because of its influence on these measured properties. This work has supplemented the significant amount of special core analysis undertaken by Shell. Coring Fluids. The routine use of oil-based mud to drill deviated wells from North Sea platforms presents a potential problem for special core analysis studies because such muds may alter the wettability of the reservoir rock.2,3 Tests have been performed to evaluate the effects of coring fluids on special core analysis results. Fig. 3 shows the results from tests on core plugs from the Brent field, conducted to evaluate an oil-based mud being considered for a coring program. Because preserved core material was not available, the plugs were resaturated with oil and water. The brine-saturated core plug was centrifuged to a low brine saturation, saturated with oil, and allowed to imbibe brine spontaneously (Step 1). The water saturation during imbibition increased by 40 saturation units. After the sample was returned to a low brine saturation, it was flushed with oil-based mud filtrate and aged for 4 days. The filtrate was then displaced with refined oil and the plug was immersed in brine (Step 2). This time, little water was imbibed; water saturation changed by less than 5 saturation units. The apparent wettability alteration was confirmed by waterflooding the plug to a low oil saturation and then allowing it to imbibe oil spontaneously (Step 3). Coring Fluids. The routine use of oil-based mud to drill deviated wells from North Sea platforms presents a potential problem for special core analysis studies because such muds may alter the wettability of the reservoir rock.2,3 Tests have been performed to evaluate the effects of coring fluids on special core analysis results. Fig. 3 shows the results from tests on core plugs from the Brent field, conducted to evaluate an oil-based mud being considered for a coring program. Because preserved core material was not available, the plugs were resaturated with oil and water. The brine-saturated core plug was centrifuged to a low brine saturation, saturated with oil, and allowed to imbibe brine spontaneously (Step 1). The water saturation during imbibition increased by 40 saturation units. After the sample was returned to a low brine saturation, it was flushed with oil-based mud filtrate and aged for 4 days. The filtrate was then displaced with refined oil and the plug was immersed in brine (Step 2). This time, little water was imbibed; water saturation changed by less than 5 saturation units. The apparent wettability alteration was confirmed by waterflooding the plug to a low oil saturation and then allowing it to imbibe oil spontaneously (Step 3).

Effective Integration of the Core Analysis and Wireline Datasets-Using a New Core Analysis Data Suite and New Software

“…The analysis of routine core data of Brent Group reservoirs in the North Sea showed a large difference between porosity-permeability trends, even within almost uniform sands. 23 Such trends were also evident when relative permeability curves of the different facies were obtained, thus supporting the need for a lithotype based approach.…”

Three-dimensional modeling of clinoforms in shallow-marine reservoirs: Part 2. Impact on fluid flow and hydrocarbon recovery in fluvial-dominated deltaic reservoirs

“…Although we recognize that petrophysical properties vary within facies-association types, we do not explicitly include these heterogeneities because they occur over lengthscales smaller than a single grid block in the models ( Figure 1D-F). The same relative permeability data, which are typical of water-wet reservoirs in the North Sea (e.g., Anderson, 1987;Stiles and Hutfilz, 1992), were applied to each facies association. Capillary pressure curves are dependent on the facies-association type.…”

On the Use of Particle Size Distribution Data for Permeability Modeling

“…Many practitioners have stressed the importance of permeability and its distribution for many aspects of reservoir management, including construction of simulation models for efficient reservoir analysis and planning and implementation of completion strategies for successful oil production (e.g., Chopra et al 1989;Stiles and Hutfilz 1992).…”