Why should I pay you to analyze my DST?

How much does it cost?

I run the same times on my DSTs as my grandfather did, why should I change?

Why would I run an Extended Well Test?

Is there a way to determine the Gas in Place on a flowing gas well without shutting it in?

What about pumping oil wells?

What is a Reservoir Simulation?

Does your company provide "Expert Testimony"?

Why should I pay you to analyze my DST?

In Kansas I feel that for many formations the DST is the best tool to evaluate the well for completion. Unfortunately in years past it has been purely a "Qualitative" technique. With the advent of powerful computers and sophisticated software, "Quantitative" analysis can now be performed.

A good analogy would be to compare a RAG log to a modern full logging suite. The RAG log gives you an idea that the zone may produce, but no calculations as to the water saturation or porosity. The full suite gives the full story.

A full DST analysis is similar to a full logging suite. Skin Damage, permeability and initial rates may be calculated to assist in the completion decision.

For example. A well was drilled and tested via DST. The operator decided to plug the well. Years later a second operator approached us to evaluate the DST. We determined that the well would produce in excess of 100 bopd on completion. This "dry hole" was washed down and put on production at over 100 bopd.

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How much does it cost?

Currently we charge $400 for a complete DST analysis with a written report.

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I run the same times on my DSTs as my grandfather did, why should I change?

Before computer aided analysis of DSTs was available each operator had their own rules of thumb of the "best" times to run the test. Now with computer aided analysis all of this has changed, there is a quantifiable "best" way to do it.

Elsewhere on the website is a page outlining in detail the times Schlumberger and Amoco recommend.

The thought process goes like this.

The Initial Flow/Shut-in period is simply for measuring the original bottom hole pressure. The only way to measure the pressure is to remove any drilling fluid that has been lost to the zone. This fluid acts to raise the pressure.

However only the amount of fluid lost to the zone should be removed. Any fluid removal over this volume acts to decrease the measured pressure. If too much fluid is removed the pressure must be calculated instead of measured.

The Final Flow/Shut-in portion is where the quantitative analysis is performed. The accuracy of the calculation is directly proportional to the amount of fluid withdrawn during the test. It is possible to introduce so much fluid into the drill sting during the Initial Flow that the Final Flow period introduces so little that calculations are impossible.

In summary Initial Flow periods longer than about 5 minutes prevent the measurement of the true bottom hole pressure and they decrease the accuracy of the Final Flow calculations.

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Why would I run an Extended Well Test?

Extended well tests can be divided into two types, New Discoveries and Existing Production

With new discoveries the question often centers on the viability of laying a gas line. Here a proper DST analysis is critical to determine the proper flow/shut-in times. The flow must be calculated in order to assure that a large enough area has been tested. The shut-in must be long enough to measure the bottom hole pressure, instead of being forced to extrapolate the data.

With existing production there is only one variable, the shut-in time. Since the well has been flowing for some time, an adequate shut-in is required. A DST is also helpful here.

An extended test typically yields the following data:

• Remaining Gas in Place
• Formation Permeability
• Current Reservoir Pressure
• Extended Production Forecast
• Zone Geometry - Faults, permeability barriers, water drive etc.

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Is there a way to determine the Gas in Place on a flowing gas well without shutting it in?

A technique call "Pseudo-Steady State Analysis" is available that determines the Original Gas in Place based on flowing casing pressures. This technique can be applied to any flowing gas well without a packer. It can be thought of as a "flowing P/z" and is very accurate.

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What about pumping oil wells?

It is virtually impossible to run a downhole pressure build up on a pumping oil well, but a pressure analysis is still available. With the assistance of some advanced software, historical pressure, and cumulative production data from pumping oil wells, can be used to determine Original Oil in Place. In its simplest form this is a material balance on the fluids in the formation.

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What is a Reservoir Simulation?

A Reservoir Simulation is a mathematical model used to forecast the production from a reservoir. We use it primarily to determine the viability of waterflood projects, but it has many other uses.

Gas Fields - We recently modeled a gas field to determine the viability of installing a gas processing plant. Without the simulator it would be difficult to forecast the production with any sort of confidence. It also allowed us to choose the optimum locations for infill drilling. We were able to differentiate between rate acceleration and new reserves.

Oil Fields - In addition to waterflood studies, the simulator is an excellent tool for determining development locations. Too often fields are overdeveloped because of lack of analysis. A reservoir simulation is a cheap way to ask "what happens if I drill here".

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Does your company provide "Expert Testimony"?

The Managing Partner of Discovery Capital L.L.C. has been accepted as an expert in the area of oil and gas litigation before the K.C.C. and state courts. He is a Registered Professional Engineer in the State of Texas.

We have provided reserve evaluations for the Internal Revenue Service for estate planning purposes as well as dispute resolution.

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