Vertical and lateral pressure variations in petroleum reservoirs result from (1) initial pressure isolation that developed over geological time; (2) pressure seals and baffles that become apparent during production or injection; (3) dynamic pressure gradients due to production, injection, or aquifer movement; and (4) static fluid density variations due to gravity segregation or compartmentalization.

Such variations provide valuable insights into key aspects of reservoir management, such as reserves per well, fluid contacts, pressure support, conformance and sweep, among others. As a result, much effort is expended in elucidating both initial pressure architecture and how pressure variations develop through time.

In most fields today, two tools dominate pressure data collection: high-resolution tools run in open well bores; and down-hole gauges provide measurements from producing wells. Tools run in open hole prior to completion (e.g., MDT, FMT, and Geotap, among others) allow numerous pressure measurements to be taken. Although requiring careful quality control, these tools measure pressure and depth to a high degree of accuracy and are commonly used to determine fluid gradients in individual sands. By contrast, down-hole gauges provide pressure measurements indicative of the average/highest pressure of the completed interval, but with the invaluable ability to monitor pressure decline over time. In the future, fiber-conveyed optical tools will enable real-time fluid, pressure, and rate discrimination that will further enhance the understanding of subsurface architecture and fluid distribution.

Both types of currently available data can be displayed on range plots to demonstrate the interaction between pressure, depth, stratigraphy, time, and location. Plots that show pressure against depth are particularly useful in illustrating fluid gradients, fluid contacts, and large-scale pressure differences. Datumed pressure plots, where the effect of fluid density is removed, reveal subtle pressure variations and changes, in particular dynamic pressure gradients caused by production and static pressure gradients, which are the result of variable fluid properties. Normalization of these data to account for differences in the magnitude of pressure depletion between early and late wells allows barriers and baffles to be ranked and mapped across a reservoir.

These techniques have been applied and refined in the ACG field located 120 km southeast of Baku, Azerbaijan. The field comprises three distinct culminations: Azeri, Chirag, and Gunashli. The northern tip of the structure began production in 1980. The remainder of the field has reserves in excess of 5000 MMBO and is subject to a 30-year production sharing agreement (PSA) operated by BP on behalf of AIOC. Initial production within the PSA began from Chirag via a 24-slot platform in 1997. Water injection commenced in 2000 and Chirag has now produced more than 200 MMBO. The extensive suite of pressure data that has been collected to monitor this production and to appraise the remainder of the structure allows a wide range of pressure effects to be illustrated.

Pressure-time plots demonstrate excellent lateral pressure communication. The lateral pressure baffles and barriers that do exist are widely spaced and correspond to the few large faults within the field. By contrast, pressure depth plots, and datumed pressure plots demonstrate clear vertical pressure barriers. They also reveal strong dynamic gradients in oil leg due to production and injection, and a dynamic aquifer.