The Paleocene/Eocene age First Eocene dolomite reservoir is estimated to contain than 10 billion barrels of oil of which only a small percentage will be produced during primary development. Consequently, steam flooding is being investigated as an appropriate EOR option. A 1.25-acre, single pattern pilot (SST) and a 40-acre, 16 pattern pilot (LSP) are in progress. The detailed pilot area log, core, and seismic data provide a unique opportunity to assess reservoir heterogeneity. Analysis of temperature and petrophysical logs obtained in a temperature observation well located 35 feet from the SST injector show that a vertical barrier to steam migration exists. Two, relatively thick, very low porosity and very low permeability nodular evaporite-rich zones that were predicted to be the most likely barriers do not appear to be a vertical barrier. Instead, an interval characterized by numerous thin, cycle caps, characterized by muddy, finely crystalline dolomites interpreted to be tidal flat facies may be the vertical barrier. Each of these cycle caps also exhibit signs of subaerial exposure which may also contribute to the generally low porosity and very low permeability of the cycle caps. Detailed studies, including micro-permeameter measurements, quantitative mineralogical studies, and micro-CT scans were used to further characterize this interval. The geological assessments of heterogeneity are supplemented by a history-matched simulation model that suggests the evaporite-rich zones may have acted as short term baffles but that the vertical barrier to steam migration is coincident with the interval with abundant tidal flat cycle caps and exposure surfaces. Geological and other reservoir data obtained from the LSP suggest that similar vertical barriers may exist in the pilot area. Early steamflooding results show a very positive response to steam injection as well as multiple thermal "events" (most likely baffles rather than barriers) in the lowermost flooded zones at the LSP. The LSP data allows inferences to be made regarding the occurrence and distribution of lateral high permeability "connections" between injectors and producers as well as the overall reservoir response to steam injection. While the rapid temperature response observed in a few wells may reflect localized fractures or karst-like zones, numerical simulation using very fine grids (1.25 m cell size) shows that some of the LSP wells may experience very short breakthrough times without the need for fracture or karst-like zones.

A large scale steamflood pilot test has been underway since 2008 in the first Eocene reservoir in the Wafra Field in the Partitioned Zone (PZ) between Saudi Arabia and Kuwait. The first Eocene is a carbonate reservoir and it is the shallowest reservoir in the Wafra Field with an average depth of 1,000 feet The primary objective of the pilot is to reduce technical and economic risk/uncertainty to determine whether full field steamflood development is feasible. The pilot consists of sixteen 2.5 acre inverted 5 spot patterns with associated steamflood and production facilities. The injection interval is the 1st Eocene "C" interval at a depth of 1300 ft. This is the first multi-pattern steamflood of a carbonate reservoir in the Middle East. This presentation will share the early results from the implementation of the pilot project. The production response to carbonate steamflooding will be shown along with examples of individual well production behavior. Early insights into carbonate steamflood response, variability of production response by pattern and the identification of operating issues associated with carbonate steamflooding will be shared. The success of the pilot test project has huge implications to not only the PZ, but to the entire Middle East region due to the vast amount of oil contained in reservoirs that would be considered targets for the steamflood process. Conclusions and lessons learned that can be drawn from carbonate steamflooding results to date in the pilot will also be shared in the presentation

Summary Effective matrix acidizing in Kuwait's horizontal openhole wells is a big challenge. Reservoir heterogeneity and the length of the horizontal wells make acid placement and diversion difficult, particularly in high-water-cut (WC) wells in which water has broken through as a result of high-permeability streaks or natural fractures. Furthermore, acid penetration is limited by the large surface area of the horizontal wellbore, and this is exacerbated by the relatively small injection rate imposed by the use of coiled tubing (CT). To make matters worse, formation damage in horizontal wells is usually very deep as a result of long exposure times. This paper discusses the application of a new viscoelastic-surfactant (VES)-based, self-diverting acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a new nonparticulate material that forms a highly viscous plug when it contacts water and that degrades when mixed with oil in the formation. The new fluid system is pumped before the acid treatment to effectively prevent the acid from stimulating high-water-saturation sections. The field results show significant improvement in post-stimulation production, owing to effective diversion and water-production control compared with wells in which a conventional polymer-diversion technique was used in the past with no consideration for water-production control in high-WC cases. The new technique has been selected as the standard stimulation practice in most horizontal openhole carbonate wells in Kuwait.

Effective matrix acidizing in Kuwait's horizontal openhole wells is a real challenge. Reservoir heterogeneity and the length of the horizontal wells make acid placement and diversion difficult, particularly in high water-cut wells in which bottom water has broken through high permeability streaks or natural fractures. Furthermore, acid penetration is limited by the large surface area of the horizontal wellbore and is exacerbated by the relatively small injection rate imposed by the use of coiled tubing. To make matters worse, formation damage in horizontal wells is usually deep due to long exposure times. This paper discusses the application of a new viscoelastic surfactant-based, self-diverting acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a new non-particulate material that forms a highly viscous plug when it contacts water, and degrades when mixed with oil in the formation. The new fluid system is pumped prior to the acid treatment to effectively prevent the acid from stimulating high water saturation sections. The field results show significant improvement on post stimulation production owing to effective diversion and water production control, compared with wells in which a conventional polymer diversion technique was used in the past with no consideration of high water cut cases. The new technique has been selected as the standard stimulation practice in most horizontal openhole carbonate wells in Kuwait. Introduction The Wafra field, discovered by Aminoil and Pacific Western (Inter Getty Oil) in 1954, is located in the Partitioned Neutral Zone - an area between the Kingdom of Saudi Arabia and Kuwait. The mineral rights in this region are shared equally between the two countries. The field is now operated by Saudi Arabian Texaco (SAT), a 100% owned subsidiary of Chevron, and Kuwait Gulf Oil Company (KGOC). SAT operates the field on behalf of the Kingdom of Saudi Arabia under the concession agreement signed in 1949. Out of the six reservoirs in the Wafra field, the most prolific is the Lower Cretaceous Ratawi Oolite. Production from this reservoir started in 1957 with 24°API being produced primarily under solution gas drive. By 1988, the average reservoir pressure had declined to 1,780 psi from initial reservoir pressure of 3,140 psi after production of almost 600 million bbl oil. Production curtailment was being considered as an alternative to reduce the pressure decline. The field was shut-in during the Gulf War and was then brought on-line shortly thereafter with extensive development drilling program. While the field was shut-in, the average reservoir increased to 2,302 psi, signaling the presence of a moderately active aquifer. The Ratawi Oolite formation permeability varies from 1 md to 1269 md and porosity ranges from 15% to 26%, with an average of 202 md and 21% respectively. The formation temperature is 150ºF. The current reservoir pressure of the main area has dropped to 1,800 psi, whereas the east-west area remains as high as 2,200 psi due to less development.

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