An offshore Abu Dhabi carbonate oil field was discovered in 1969 and put on production in 1985. The field has two separate culminations producing from a reefal limestone formation deposited in the middle cretaceous. The northern culmination is characterized by good reservoir properties and supported with an active bottom water drive while the southern culmination is characterized by low reservoir properties and hence less support from the aquifer.
Initially the reservoir was developed by vertical and/or deviated oil producers and peripheral water injectors. Soon after production starts, wells water cut gradually increased to reach 50% within 4–5 years with drastic decline in oil production.
Horizontal drilling was implemented with an objective of increasing well exposure to reservoir, reducing drawdown and as such combating water coning/channeling phenomena. Although oil production from horizontal wells was substantially improved, water production trend and production decline, however, did not change in most of the cases.
Application of ESP in southern and northern culminations was initiated to overcome high water cut problem and hence elongates and improves wells production lifting capacity. ESP wells performance shows encouraging results, particularly in the southern culmination.
Managing this offshore reservoir at such high water production is one of the major challenges facing field development engineers. Reservoir heterogeneities, such as fractures and facies distribution, are believed to be main contributors to a water coning/channeling phenomena and to the escalation of water production trends. Therefore, understanding of geological, petrophysical, properties of the formation is the corner stone for, controlling water production problems and hence improving reservoir performance.
This paper provides an overview of the factors that are contributing to the rapid increase in water production and the associated decline in oil production, the vertical wells, horizontal & ESP performance. The paper also assesses new potential ideas for future development aiming towards increasing the sustainable production and recovery.
Background:
This field is located approximately 25 km North-West offshore Abu Dhabi. To date, the total number of drilled wells in the field are 61 wells; 18 wells are water injectors, 26 oil wells, remaining of the wells are either observers and/or delineation wells. Producing wells are connected to seven oil well head platforms, where wells can be flow-tested and their production gathered to single flow lines, and then transferred to the central production complex (CPC) supported by their well head pressures. Associated gas is then separated using two-phase separators installed at CPC while fluid (oil & gas) from production separators are pumped and sent to the main oil line "MOL", where it entirely mixes with other field crude oil before reaching the final separation plants and export facilities.
As far as well completion, 23 wells are horizontal, while the remaining three wells are still deviated producers. Most of the oil producing wells are naturally flowing, except five wells that were equipped with electrical submersible pumps "ESPs". All wells are completed with single production strings. It's worth noting that most of the wells that were drilled as vertical/deviated, are horizontal side tracked in a later stage.
Moreover, recently acquired 3D seismic data revealed the existence of extensive reservoir heterogeneity features such as faults and fractures.
The field was initially developed by vertical/deviated oil producers and powered peripheral water injection. As mentioned, the field is divided into two areas, North and South. They are treated separately as their performance tend to behave differently. Pressure regime, PVT and fluid contact data, all suggest that the two culminations are isolated.
Sustaining target production rate in this field is considered as one of the major challenges facing field development teams, mainly due to excessive water production and reservoir heterogeneity. Current water cut is around 50%. Current practices in maintaining target rate and arresting water cut escalation is by drilling new wells and placing horizontal laterals in the very top reservoir, about 10–15 feet below the cap rock. Despite these well placement techniques, water production finds its way to newly drilled laterals and in couple of years time water cut stabilizes to a level similar to the old wells levels. Water coning, unfavorable mobility ratio in addition to reservoir heterogeneity are believed to have largely attributed to early water breakthrough in almost all of the producers.
Northern area reservoir contains about 60% of the field's OOIP. It is also characterized by the presence of a thick transition zone and unfavorable fluid mobility conditions. The dry oil zone, excluding transition zone, which is located in the very crestal part of reservoir structure contains only 30–40% of this oil in place. Most of the existing wells are targeting dry oil zone, as wells drilled in the transition zone are currently idle due to high water cut and/or poor reservoir characteristics. As far as production concern, northern area contribution to total oil production is around 74%, while the rest comes from the southern area ESP wells.
The water injection started in 1986, just one year after production commissioning. Water injection is taking place in the aquifer, below the oil water contact. There are now 15 peripheral water injectors assigned to northern reservoir area, while two wells injecting in the southern area. All water injectors are veridical/deviated, except one horizontal water injectors in the south.
