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PSPrediction of Sub-seismic Sealing Faults Previous HitUsingNext Hit Simple Numerical Simulation Models*

By

R.C. Bain1, K.H. MacIvor1, B.E. Holt1, and D.S. Beaty1

 

Search and Discovery Article #40242

Posted May 28, 2007

 

*Adapted from poster presentation at AAPG Annual Convention, Long Beach, California, April 1-4, 2007

 

1Chevron North America Upstream, Houston, Texas ([email protected])

 

Abstract 

In order to justify development drilling in a partly-depleted, highly faulted gas reservoir in which untapped higher-pressure compartments may exist, convincing evidence for Previous HitfaultNext Hit separation from existing producing wells must be provided, either by obvious Previous HitfaultNext Hit breaks on 3-D seismic or by missing section due to a Previous HitfaultNext Hit encountered in a well. Lacking such evidence, it is difficult to state with certainty that prospect reserves will be incremental, as opposed to acceleration, even when volumetric analysis suggests that existing wells will not capture all of the producible reserves in a reservoir.  

The Mid-Continent Business Unit of Chevron North America Exploration and Production has had success in the Lobo Trend of Webb and Zapata Counties, South Texas, Previous HitusingNext Hit simple, "fit-for-purpose" 3D-earth models and numerical simulation models that provide a level of confidence sufficient to predict the location and expected reservoir conditions of remaining incremental reserves in a partly-developed reservoir. These models have proven to be very useful in their ability to provide quick results with limited geologic and reservoir data. The key factor in their success is the proper integration of flowing pressure data with observed production decline curves. Static reservoir pressure measurements are typically unavailable and also give misleading results when used for P/Z volumetric analysis in compartmentalized reservoirs. 

In the first example, a simple simulation model predicted the presence of sub-seismic faulting that provided a seal for the objective reservoir. The proposed location was in a syncline between two wells that had already produced large volumes of gas and were producing at very low bottom-hole pressures. An iterative approach involving the seismic interpreter and the reservoir engineer resulted in a geologic model that was supported by the seismic data and agreed with the history matching efforts. The well, which would not have been approved without the model to support it, encountered near-virgin reservoir conditions. 

The second example provides a lesson learned, demonstrating a reservoir in which the reservoir simulation and history match correctly predicted the presence of a sealing Previous HitfaultNext Hit, but incorrectly predicted which of several faults was the sealing one. The sealing Previous HitfaultNext Hit was penetrated by the wellbore and the seal was ruptured when the well was fracture stimulated. 

Quickly demonstrating the accuracy and applicability of simple numerical models in an environment where rig moves are rapid and reservoir data is sparse has generated a new interest in a tool that was heretofore thought too complex and too Previous HittimeNext Hit consuming to apply. Asset Team Earth Scientists are now working more closely with the reservoir simulation engineers and are Previous HitusingNext Hit the results from these simple models to help in their Previous HitinterpretationNext Hit of subsurface geology, especially in highly faulted environments. In some cases, successful wells are being drilled where they otherwise would not have been.

 

uAbstract

uPoster 1

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uCase Study #1

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uCase Study #2

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uLessons Learned

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uAbstract

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uBest Practices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uPoster 1

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uCase Study #1

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uCase Study #2

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uLessons Learned

uBest Practices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uPoster 1

  uProblem

  uFigures

uCase Study #1

  uFigures

uCase Study #2

  uFigures

uLessons Learned

uBest Practices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

uAbstract

uPoster 1

  uProblem

  uFigures

uCase Study #1

  uFigures

uCase Study #2

  uFigures

uLessons Learned

uBest Practices

Poster 1: The Problem, Geologic Setting, and Reservoir Simulation Basics 

The Problem 

Volumetric calculations indicate that two wells producing from the same gas reservoir  have not drained all of the producible reserves in a 200-acre Previous HitfaultNext Hit block. The challenge is to identify economic drill locations despite the fact that the existing wells appear to be depleted.

 

Selected Figures 

 

Posters 2 and 3: Case Study #1 

A 3-D seismic Previous HitinterpretationNext Hit of the Previous HitfaultNext Hit block described above was converted to a GOCAD model and assigned reservoir properties. A 3-D cellular model was then constructed. History matching of the actual well performance to the numerical simulation indicated that internal boundaries were required to adequately explain the pressure and rate performance of the wells. This caused the seismic interpreter to revise the 3-D model. 

By interpreting tiny offsets of flexures in seismic events as possible faults, the seismic interpreter was able to segment the objective reservoir into four blocks (see Line A-A’). The 3-D cellular model was revised to incorporate the new barriers, and the simulation was run again. This Previous HittimeNext Hit the pressure and production history of the wells matched the simulation model closely. This provided the confidence necessary for proposing additional wells to fully develop the block. Prior to the revised Previous HitinterpretationNext Hit, the presence of the existing, nearly depleted wells in the block would have discouraged any additional drilling. Results of two new wells demonstrate that the revised Previous HitinterpretationNext Hit was correct. This 3-D Previous HitinterpretationNext Hit would not have been made without the results of the simulation, which suggested that additional faulting was present.

 

Selected Figures 

  

Poster 4: Case Study #2 

In a different part of the model created in Case Study #1, a well was proposed to offset a competitive drainage situation in a 60-acre Previous HitfaultNext Hit block. The proposed well was expected to encounter similar pressure to a recently drilled updip well. An unexpected 80-foot Previous HitfaultNext Hit was encountered in the objective reservoir when the well was drilled, but the pressure matched what had been predicted by the simulation model. However, after fracture stimulating the well, the observed pressure had decreased by more than 2000 psi. The Previous HitfaultNext Hit encountered in the well was apparently a seal between two compartments of vastly different pressure. The stimulation ruptured the seal and the frac job “went south.”

 

Selected Figures 

  

Lessons Learned 

  • Reservoir simulation does not need to take several months or years to add value. Simple models can generate significant value with a few days of technical work.

  • P/Z volumetric analysis applied to a compartmentalized gas reservoir cannot accurately predict pre-drill reserve potential, especially in low-permeability gas reservoirs.

  • Flowing pressure data is readily available as commercial data and can be used to determine drainage areas in gas wells, when accurate static pressure data is unavailable.

  • Simple numerical simulation models:

    • Work well in an environment where there is sparse reservoir and temporal data.

    • Can be used routinely in daily reservoir engineering tasks and problem solving by ALL reservoir engineers.

    • Work nicely in an environment where rig moves take place very two to three weeks.

  • Inflection points on seismic events can sometimes indicate faulting, even if no offset is observed.

  • Sealing faults can be breached by fracture stimulations.

 

Best Practices 

  • Start simple—add complexity over Previous HittimeTop only if necessary. Simple models work.

  • Sparse data does not need to inhibit the use of reservoir simulation.

Flowing tubing pressure (converted to bottom hole flowing pressure) can be used for the pressure match when other reservoir pressure measurements are unavailable

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