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PSOne Previous HitDirectNext Hit Indicator for Reservoir in Fractured Carbonate*

By

GuangJun Chen1, Mohamed Redal1, Jianguo Zhu2, and Wei Meng2

 

Search and Discovery Article #40258 (2007)

Posted September 2, 2007

 

*Adapted from poster presentation at AAPG Annual Convention, Long Beach, California, April 104, 2007

 

1Schlumberger, Beijing, China ([email protected])

2Northwest Bureau, SinoPec

 

Abstract

The reservoirs in the Tahe oilfield are fractured carbonates with extremely severe anisotropy, typically karsted. The rock is a very tight limestone, with matrix porosity of < 2%. Vugs and caves connected by natural fractures are the storage. Reservoirs are developed along with a weathering crust. Some wells produce oil at a relative high rate, while others have a very quick breakthrough or produce water initially. Accurate characterization of the reservoirs to enable increased oil and decreased water production is a challenge.  

In an attempt to directly characterize the reservoirs seismic variance was used, which calculates the Previous HitdirectNext Hit measurement of dissimilarity of seismic traces and produces much sharper and more distinct terminations than those observed in normal amplitude data. Calibrated with core, log, and high-resolution resitivity data, fractures, caves, and vugs are all shown to result in high variance values, indicating that a reservoir can be developed only where variance shows high values. Variance results are displayed in 3D or in cross-sections, and are used to identify the geological features in the volume. Based on the variance Previous HitindicatorsNext Hit, caves and vugs can be directly identified to predict the carbonate reservoirs, which significantly aids properties modeling and production management.  

While seismic variance does not provide a perfect definition of the reservoir, it has proven to be a reliable Previous HitdirectNext Hit indicator for reservoir facies in the fractured carbonates of the Tahe field.

uAbstract

uBackground

  uFigures

uSolution

  uFigures

uIndications

  uFigures

uConclusion

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uBackground

  uFigures

uSolution

  uFigures

uIndications

  uFigures

uConclusion

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uBackground

  uFigures

uSolution

  uFigures

uIndications

  uFigures

uConclusion

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uBackground

  uFigures

uSolution

  uFigures

uIndications

  uFigures

uConclusion

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uBackground

  uFigures

uSolution

  uFigures

uIndications

  uFigures

uConclusion

Background and Challenges 

  • Structurally, the area is relatively simple, gently sloping from northeast to southwest.

  • The rock is a very tight limestone, with matrix porosity being < 2%.

  • The reservoir porosity developed as a result of long-term weathering and erosion, its storages are vugs and caves connected by natural fissures.

  • The Ordovician system is the main Previous HithydrocarbonNext Hit carrier.

  • Reservoirs have extremely severe anisotropy.

  • Some wells produce oil at a relatively high rate while others have a very quick breakthrough or produce water initially.

  • How to characterize the reservoirs to enable increased oil and decreased water?

 

Figures 

Depth surface of target Ordovician.

Evolution of the karst system.

Production out of the karst system.

Breccia and vug.

High angle corrosion fracture.

 

Solution and Workflow 

  • Used seismic variance process to calculate the Previous HitdirectNext Hit measurement of dissimilarity of seismic data to highlight much sharper, more distinct terminations.

  • Combined geological analysis and log data interpretation to describe the fine differences related to faults, fractures, and strata information such as the bounding limits of a reservoir.

  • Reservoir style determination.

  • Seismic variance processing.

  • Abnormities calibration with logging data.

  • Abnormities validation with production testing.

  • Fractured reservoir identification and description.

  • Characterization output for modeling.

 

Figures 

Seismic variance processing, 20 ms and 5x5 result were used.

Fractured variance abnormality validated by well and core.

Vug variance abnormality with logging curves.

Variance abnormalities, identification and characterization.

 

Indications 

  • Reservoir can only develop at big variance abnormalities.

  • No variance abnormalities, no reservoir.

  • Standing or vertical variance abnormalities represent the existence of vertical fractures or small faults, which play an important role in reservoir connection.

  • Upper variance abnormalities produce oil while lower usually do so with water, if they are connected by vertical fractures (possibly with oil & water).

 

Figures 

Logging interpretation validates the variance indications.

Variance indications of different types of reservoir.

Variance abnormalities indicate bottom water.

Fractured carbonate reservoir model.

Caves and vugs can be identified on logging data.

Field reservoir properties statistics: Tight fractured carbonate.

Karst layers validated by formation images.

Production testing statistics: Vadose and Phreatic are major net pay zones.

Variance abnormalities calibrated by logging data.

Real story: Before sidetrack no production; after sidetrack (according to variance abnormalities) a good producer.

 

Conclusion 

While seismic variance does not provide a perfect definition of the reservoir, it has proven to be a reliable Previous HitdirectTop indicator for reservoir facies in the fractured carbonates of the Tahe field.

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