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Collaborating Authors
Exploration, development, structural geology
Abstract Many hydrocarbon reservoirs have an oil bearing zone, sandwiched between gas and water bearing zones. For these reservoirs, considerable studies are conducted to optimize the location of wells in the oil rim so as to maximize oil recovery. Few studies however have investigated the conditions under which wells could be located in either the gas cap or the water leg so as to also maximize oil recovery. This study investigates the effect of gas cap and aquifer sizes on oil recovery from a reservoir with a thin oil rim using a single well numerical reservoir simulator model. Sensitivity studies were conducted by varying gas cap size, aquifer size and well location, and analyzing their effect on oil recovery. The results indicated that for a reservoir with a large gas cap, it may be more favorable to place the horizontal well below the water-oil contact; for a reservoir with a small gas cap and large aquifer, it may be advantageous to place the horizontal well above the gas-oil contact. This study is significant since thin oil rims are especially prominent in the prolific gas province offshore the east coast of Trinidad, and maximizing oil recovery, the more valuable resource, has positive financial implications.
- Europe (1.00)
- Asia > Indonesia (1.00)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean (0.29)
- North America > United States > Texas (0.28)
- Oceania > Australia > Western Australia > Timor Sea > Bonaparte Basin > Vulcan Basin > PL AC/L8 > Skua Field (0.99)
- Oceania > Australia > Western Australia > Timor Sea > Bonaparte Basin > Vulcan Basin > PL AC/L7 > Skua Field (0.99)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > East Mayoro Block > Mahogany Field (0.99)
- (17 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Abstract The Dolphin Field is located in the East Coast Marine Area, approximately 60km off Trinidad. It comprises a 5,000 feet succession of stacked, unconsolidated, Pleistocene shoreface-deltaic sandstones and mudstones lying within a three-way dip, fault closure. The field is complicated by poor seismic data due to gas attenuation, fault shadow effects, large velocity variations and noise in the overburden. As a result the use of seismic amplitudes for fluid determination is unreliable and fault interpretation problematic. Despite over 15 years of production, 5 exploration wells and 13 development wells there remains a high level of subsurface uncertainty. Specific areas of uncertainties include: zones of poor correlation as a result of large-scale sediment deformation; the configuration and sealing properties of both structural and syn-sedimentary faults; the effects of thin-bedded deposits (forming over 50% of the Dolphin reservoir intervals) on reservoir pay and connectivity; and the absence of all but one proven Gas Water Contact (GWC). Defining the range of these uncertainties has a key impact on the range of GIIP outcomes, the resultant development plan and subsequent reservoir management. This paper will discuss the challenges and impact of these uncertainties on the Dolphin Field. The uncertainties identified on Dolphin form the basis for uncertainty planning in the development of subsequent analogous greenfields also within the Greater Dolphin Area.
- North America > United States (1.00)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean (1.00)
- Oceania > Australia > Victoria > Bass Strait (0.72)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.69)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > East Coast Marine Area > Block 5A > Dolphin Field (0.99)
- Africa > Middle East > Egypt > Nile Delta > Nile Delta Basin > Sequoia Field (0.99)
- Europe > Romania > Black Sea > West Black Sea Basin > Dolphin Well (0.98)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > East Coast Marine Area > Starfish Field (0.93)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract The BP Trinidad gas fields are located in the Columbus basin, 35-40 miles off the southeast coast of Trinidad in water depths of between 200 to 300 feet. The fields are comprised of highly faulted stacked sandstone reservoir units of varying ages between Quaternary to Pleistocene. Most reservoir units contain original gas in place of less than 0.5 tcf and are usually produced by one or two wells. The shallow gas reservoirs (< 4500 ft TVDSS) constitute a significant percentage of the non-producing BP Trinidad gas portfolio. Reservoir data, such as rock compressibility, and performance data such as recovery factors are lacking in both the local and global database for analogous reservoirs at these depths. Initially these shallow gas reservoirs were considered as drilling hazards for deeper reservoirs therefore well paths and platform locations avoided them as recovery from them were initially expected to be very poor. The shallowest producing reservoir unit to date is from the TP95 reservoir in the Greater Cassia Field Complex and it has one producer. This reservoir depth is 4200ft TVDSS and it has been on production since 2003, exceeding expectations with its recovery. This paper investigates the key uncertainties associated with this reservoir including depth conversion (since it is overlain by other shallow gas reservoirs), rock compressibility and aquifer support. It also shows the well and reservoir performance data, key surveillance data collected as well as types of analysis and modeling performed to help understand and predict the reservoir performance given the aforementioned subsurface uncertainties.
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > Cassia Field (0.99)
- North America > Trinidad and Tobago > Trinidad Field (0.98)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
Race for Liquids vs Gas: How To Redesign a Depletion Strategy to Maximise Fluids Recovery in a Mature Thin-Oil Rim Reservoir
Moosai, R.. (BP) | Alleyne, B.. (BP) | Thomas, S.. (BP) | Smith, D.. (BP) | Cavaleri, N.. (International Reservoir Technologies) | Quinn, M. Anthony (International Reservoir Technologies)
Abstract Hydrocarbon reservoir management of a mature reservoir is a complex process of deciphering the reservoir character, through dynamic static data integration, to produce an ideal depletion strategy for the field. A great result is normally a winning opportunity set or strategy defined by a marriage of maximum hydrocarbon recovery with fantastic economic indicators. Is it any wonder we invest heavily into tools and processes to achieve just this! This paper will explore the use of structural and reservoir modeling tools and techniques to re-design an optimal depletion strategy for an oil and gas reservoir, in a predominantly gas field, in the Columbus basin off the East coast of Trinidad. This reservoir is a massive ~700 ft sand incorporating a 30~40ft thin oil rim with an underlying aquifer and overlain by a huge gas cap. Both oil and gas has been produced from this reservoir since 1998 by 8 oil wells and 4 gas wells spread across two fields. Should the future of this reservoir first rely on targeting remaining oil or do we shift into high gas acceleration gear? To solve this conundrum all subsurface hands were brought on deck. The formulation of an appropriate depletion plan requires a multi pronged approach, as a clear alliance must be made between business objectives, reducing risk and good reservoir management practice. A VIP/Nexus reservoir simulation model was the ‘tool of choice’ to investigate which depletion direction to forge ahead with. The first stage of this reservoir management investigation was the creation of a reliable structural model which then acted as the foundation for the build of a representative reservoir model. As part of this paper’s journey, we delve into the process flow used to mimic this magnificent reservoir. We endeavor to deepen your understanding of, the application of crucial petrophysical modeling in the reservoir characterization procedure and the unmistakable impact of history matching over 12 years of production and pressure data. The result of this work was a fit for purpose reservoir model enabling the operator to make the right decisions for future development of this reservoir.
- North America > United States > Texas > Fort Worth Basin > Overall Field (0.99)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)